This report presents the EPA's analysis of the potential benefits, costs, and other economic effects of the final emission guidelines to fulfill the requirements of an RIA. This RIA includes the following chapters:
           Chapter 2, Electric Power Sector Profile
           Chapter 3, Control Strategies, Cost, Economic, and Energy Impacts
           Chapter 4, Estimated Climate Benefits and Health Co-benefits
           Chapter 5, Economic Impacts  -  Markets Outside the Electricity Sector
           Chapter 6, Employment
           Chapter 7, Statutory and Executive Order Analyses
           Chapter 8, Summary of Benefits and Cost of the Final Regulation
1.6	References
40 CFR Chapter I [EPA - HQ - OAR - 2009 - 0171; FRL - 9091 - 8] RIN 2060 - ZA14, "Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act," Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / Rules and Regulations.
75 FR 49556. August 13, 2010. "EPA's Denial of the Petitions to Reconsider the Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act."
Melillo, J.M., T.C. Richmond, and G.W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program. Available at <http://nca2014.globalchange.gov>. Accessed June 4, 2015.
National Research Council. Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia. Washington, DC: The National Academies Press, 2011.
U.S. Environmental Protection Agency. EPA's Power Sector Modeling Platform v.5.14. March 25, 2015. Available online at <http://www.epa.gov/powersectormodeling/psmodel514.html>. Accessed June 4, 2015.

Chapter 2: Industry Profile
2.1 	Introduction
This chapter discusses important aspects of the power sector that relate to the Final Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, including the types of power-sector sources affected by the regulation, and provides background on the power sector and EGUs. In addition, this chapter provides some historical background on trends in the past decade in the power sector, as well as about existing EPA regulation of the power sector
In the past decade there have been significant structural changes in the both the mix of generating capacity and in the share of electricity generation supplied by different types of generation. These changes are the result of multiple factors in the power sector, including normal replacements of older generating units with new units, changes in the electricity intensity of the US economy, growth and regional changes in the US population, technological improvements in electricity generation from both existing and new units, changes in the prices and availability of different fuels, and substantial growth in electricity generation by renewable and unconventional methods. Many of these trends will continue to contribute to the evolution of the power sector in the future. The evolving economics of the power sector, in particular the increased natural gas supply and subsequent relatively low natural gas prices, have resulted in more gas being utilized as base load energy in addition to supplying electricity during peak load. This chapter presents data on the evolution of the power sector from 2002 through 2012. Projections of new capacity and the impact of this rule on these new sources are discussed in more detail in Chapter 4 of this RIA.
2.2 	Power Sector Overview
The production and delivery of electricity to customers consists of three distinct segments: generation, transmission, and distribution.
2.2.1 	Generation
Electricity generation is the first process in the delivery of electricity to consumers. There are two important aspects of electricity generation; capacity and net generation. Generating Capacity refers to the EGUs that are available for use in a given year, typically measured in megawatts (MW) or gigawatts (1 GW = 1000 MW). Electricity Generation refers to the amount of electricity actually produced by EGUs, measured in kilowatt-hours (kWh) or gigawatt-hours (GWh = 1 million kWh).
Individual EGUs are not used to generate electricity 100 percent of the time. Not only are units unavailable during routine and unanticipated outages for maintenance, but individual EGUs are also periodically not needed to meet the regular daily and seasonal fluctuations of electricity demand. Furthermore, EGUs relying on renewable resources such as wind, sunlight and surface water to generate electricity are routinely constrained by the availability of adequate wind, sunlight or water at different times of the day and season. These factors result in the mix of generating capacity types available (e.g., the share of capacity of each type of EGU) being substantially different than the mix of the share of total electricity produced by each type of EGU in a given season or year.
Most of the existing capacity for generating electricity does so by creating heat to create high pressure steam that is released to rotate turbines which, in turn, create electricity. Other units generate electricity by using water or wind to rotate turbines, and a variety of other methods also make up a small part of the overall electricity supply. The generating capacity includes fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable sources (see Table 2-1). Table 2-1 also shows the comparison between the generating capacity in 2002 and 2012.
In 2012 the power sector consists of over 19,000 generating units with a total capacity of 1,168 GW, an increase of 19 percent from the capacity in 2002 (989 GW). The 188 GW increase in capacity consisted primarily of natural gas fired EGUs (134 GW) and wind generators (55 GW), with substantially smaller net increases and decreases in other types of generating units.

Table 2-1.         Existing Electricity Generating Capacity by Energy Source, 2002 and 2012

                                     2002
                                     2012
                          Change Between '02 and '12
                                 Energy Source
                       Generator Nameplate Capacity (MW)
                               % Total Capacity
                       Generator Nameplate Capacity (MW)
                               % Total Capacity
                                  % Increase
                        Nameplate Capacity Change (MW)
                         % of Total Capacity Increase
Coal
                                                                        338,199
                                                                            35%
                                                                        336,341
                                                                            29%
                                                                            -1%
                                                                         -1,858
                                                                            -1%
Natural Gas[1]
                                                                        352,128
                                                                            36%
                                                                        485,957
                                                                            42%
                                                                            38%
                                                                        133,829
                                                                            71%
Nuclear
                                                                        104,933
                                                                            11%
                                                                        107,938
                                                                             9%
                                                                             3%
                                                                          3,005
                                                                             2%
Hydro
                                                                         96,344
                                                                            10%
                                                                         99,099
                                                                             8%
                                                                             3%
                                                                          2,755
                                                                             1%
Petroleum
                                                                         66,219
                                                                             7%
                                                                         53,789
                                                                             5%
                                                                           -19%
                                                                        -12,430
                                                                            -7%
Wind
                                                                          4,531
                                                                           0.5%
                                                                         59,629
                                                                           5.1%
                                                                          1216%
                                                                         55,098
                                                                            29%
Other Renewable
                                                                         14,208
                                                                           1.5%
                                                                         20,986
                                                                           1.8%
                                                                          47.7%
                                                                          6,778
                                                                           3.6%
Misc
                                                                          3,023
                                                                           0.3%
                                                                          4,257
                                                                           0.4%
                                                                          40.8%
                                                                          1,234
                                                                           0.7%
Total
                                                                        979,585
                                                                           100%
                                                                      1,167,995
                                                                           100%
                                                                            19%
                                                                        188,410
                                                                           100%
Note: This table presents generation capacity. Actual net generation is presented in Table 2-2.

Source: U.S. EIA Electric Power Annual, 2012. Downloaded from EIA Electricity Data Browser, Electric Power Plants Generating Capacity By Source, 2000  -  2012. Available at <http://www.eia.gov/electricity/data.cfm#gencapacity.> Accessed 12/19/2014
[1] Natural Gas information in this chapter (unless otherwise stated) reflects data for all generating units using natural gas as the primary fossil heat source. This includes Combined Cycle Combustion Turbine (31 percent of 2012 capacity), Gas Turbine (30 percent), Combined Cycle Steam (19 percent), Steam Turbine (17 percent), and miscellaneous (< 1 percent).

The 19 percent increase in generating capacity increase is the net impact of newly built generating units, retirements of generating units, and a variety of increases and decreases to the rated capacity of individual existing units due to unit modifications, changes in emission control equipment, etc. During the period 2002 to 2012, a total of 315,752 MW of new generating capacity was built and brought online, and 64,763 MW existing units were retired. The net effect of the re-rating of existing units reduced the total capacity by 62,579 MW. The overall net change in capacity was 188,410 MW, as shown in Table 2-1.
The newly built generating capacity was primarily natural gas (226,605 MW), which was partially offset by gas retirements (29,859 MW). Wind capacity was the second largest type of new builds (55,583 MW), augmented by 2,807 MW of solar. The overall mix of newly built and retired capacity, along with the net effect, is shown on Figure 2-1.

Figure 2-1.	New Build and Retired Capacity (MW) by Fuel Type, 2002-2012
Source:	EIA Form 860
Not displayed: wind and solar retirements = 87 MW, net change in coal capacity = -56 MW

In 2012, electric generating sources produced a net 4,058 billion kWh to meet electricity demand, a 5 percent increase from 2002 (3,858 billion kWh). As presented in Table 2-2, almost 70 percent of electricity in 2012 was produced through the combustion of fossil fuels, primarily coal and natural gas, with coal accounting for the largest single share. Although the share of the total generation from fossil fuels in 2012 (67 percent) was only modestly smaller than the total fossil share in 2002 (71 percent), the mix of fossil fuel generation changed substantially during that period. Coal generation declined by 18 percent and petroleum generation by 63 percent, while natural gas generation increased by 61 percent. This reflects both the increase in natural gas capacity during that period as well as an increase in the utilization of new and existing gas EGUs during that period. Wind generation also grew from a very small portion of the overall total in 2002 to 4.1 percent of the 2012 total.

Table 2-2.         Net Generation in 2002 and 2012 (Trillion kWh = TWh)

                                     2002
                                     2012
                          Change Between '02 and '12

                             Net Generation (TWh)
                               Fuel Source Share
                             Net Generation (TWh)
                               Fuel Source Share
                          Net Generation Change (TWh)
                          % Change in Net Generation
Coal
                                                                        1,933.1
                                                                            50%
                                                                        1,586.0
                                                                            39%
                                                                         -347.1
                                                                         -18.0%
Natural Gas
                                                                          702.5
                                                                            18%
                                                                        1,125.9
                                                                            28%
                                                                          423.5
                                                                          60.3%
Nuclear
                                                                          780.1
                                                                            20%
                                                                          789.0
                                                                            19%
                                                                            9.0
                                                                           1.1%
Hydro
                                                                          255.6
                                                                             7%
                                                                          264.7
                                                                             7%
                                                                            9.1
                                                                           3.6%
Petroleum
                                                                           94.6
                                                                           2.5%
                                                                           26.9
                                                                           0.7%
                                                                          -67.7
                                                                         -71.6%
Wind
                                                                           10.4
                                                                           0.3%
                                                                          167.7
                                                                           4.1%
                                                                          157.3
                                                                        1519.3%
Other Renewable
                                                                           68.8
                                                                           1.8%
                                                                           85.7
                                                                           2.1%
                                                                           16.9
                                                                          24.6%
Misc
                                                                           13.5
                                                                           0.4%
                                                                           12.4
                                                                           0.3%
                                                                           -1.2
                                                                          -8.7%
Total
                                                                          3,858
                                                                           100%
                                                                          4,058
                                                                           100%
                                                                            200
                                                                             5%
Source: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All Sectors). Available at <http://www.eia.gov/totalenergy/data/monthly/. Accessed 12/19/2014

Coal-fired and nuclear generating units have historically supplied "base-load" electricity, the portion of electricity loads which are continually present, and typically operate throughout all hours of the year. The coal units meet the part of demand that is relatively constant. Although much of the coal fleet operates as base load, there can be notable differences across various facilities (see Table 2-3). For example, coal-fired units less than 100 megawatts (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 has historically supplied "peak" and "intermediate" power, when there is increased demand for electricity (for example, when businesses operate throughout the day or when people return home from work and run appliances and heating/air-conditioning), versus late at night or very early in the morning, when demand for electricity is reduced.
Table 2-3 also shows comparable data for the capacity and age distribution of natural gas units. Compared with the fleet of coal EGUs, the natural gas fleet of EGUs is generally smaller and newer. While 55 percent of the coal EGU fleet is over 500 MW per unit, 77 percent of the gas fleet is between 50 and 500 MW per unit.
Table 2-3.         Coal and Natural Gas 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)
COAL
0  -  24
                                                                            223
                                                                            18%
                                                                           40.7
                                                                           11.4
                                                                          2,538
                                                                             1%
                                                                         11,733
25  -  49
                                                                            108
                                                                             9%
                                                                           44.2
                                                                           36.7
                                                                          3,963
                                                                             1%
                                                                         11,990
50  -  99
                                                                            157
                                                                            12%
                                                                           49.0
                                                                           74.1
                                                                         11,627
                                                                             4%
                                                                         11,883
100 - 149
                                                                            128
                                                                            10%
                                                                           50.6
                                                                          122.7
                                                                         15,710
                                                                             5%
                                                                         10,971
150 - 249
                                                                            181
                                                                            14%
                                                                           48.7
                                                                          190.4
                                                                         34,454
                                                                            11%
                                                                         10,620
250 - 499
                                                                            205
                                                                            16%
                                                                           38.4
                                                                          356.2
                                                                         73,030
                                                                            23%
                                                                         10,502
500 - 749
                                                                            187
                                                                            15%
                                                                           35.4
                                                                          604.6
                                                                        113,056
                                                                            36%
                                                                         10,231
750 - 999
                                                                             57
                                                                             5%
                                                                           31.4
                                                                          823.9
                                                                         46,963
                                                                            15%
                                                                          9,942
1000 - 1500
                                                                             11
                                                                             1%
                                                                           35.7
                                                                         1259.1
                                                                         13,850
                                                                             4%
                                                                          9,732
Total Coal
                                                                           1257
                                                                           100%
                                                                           42.6
                                                                          250.7
                                                                        315,191
                                                                           100%
                                                                         11,013
NATURAL GAS
0  -  24
                                                                           1992
                                                                            37%
                                                                           37.6
                                                                            7.0
                                                                         13,863
                                                                             3%
                                                                         13,531
25  -  49
                                                                            410
                                                                             8%
                                                                           21.8
                                                                          125.0
                                                                         51,247
                                                                            12%
                                                                          9,690
50  -  99
                                                                            962
                                                                            18%
                                                                           15.6
                                                                          174.2
                                                                        167,536
                                                                            39%
                                                                          8,489
100 - 149
                                                                            802
                                                                            15%
                                                                           23.4
                                                                           39.9
                                                                         31,982
                                                                             8%
                                                                         11,765
150 - 249
                                                                            167
                                                                             3%
                                                                           28.7
                                                                          342.4
                                                                         57,179
                                                                            13%
                                                                          9,311
250 - 499
                                                                            982
                                                                            18%
                                                                           24.6
                                                                           71.1
                                                                         69,788
                                                                            16%
                                                                         12,083
500 - 749
                                                                             37
                                                                             1%
                                                                           40.0
                                                                          588.8
                                                                         21,785
                                                                             5%
                                                                         11,569
750 - 1000
                                                                             14
                                                                           0.3%
                                                                           35.9
                                                                          820.9
                                                                         11,492
                                                                             3%
                                                                         10,478
Total Gas
                                                                           5366
                                                                           100%
                                                                           27.7
                                                                           79.2
                                                                        424,872
                                                                           100%
                                                                         11,652

Source: National Electric Energy Data System (NEEDS) v.5.13
Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed to a generation-weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher level of fuel efficiency. Table is limited to coal-steam units in operation in 2013 or earlier, and excludes those units in NEEDS with planned retirements in 2014-2015.

In terms of the age of the generating units, 50 percent of the total coal generating capacity has been in service for more than 38 years, while 50 percent of the natural gas capacity has been in service less than 15 years. Figure 2-2 presents the cumulative age distributions of the coal and gas fleets, highlighting the pronounced differences in the ages of the fleets of these two types of fossil-fuel generating capacity. Figure 2-2 also includes the distribution of generation.

Figure 2-2.	Cumulative Distribution in 2010 of Coal and Natural Gas Electricity Capacity and Generation, by Age
Source: National Electric Energy Data System (NEEDS) v.5.13
Not displayed: coal units (376 MW total, 1 percent of total) and gas units (62 MW, < .01 percent of total)) over 70 years old for clarity. Figure is limited to coal-steam units in NEEDS in operation in 2013 or earlier (excludes ~2,100 MW of coal-fired IGCC and fossil waste capacity), and excludes those units in NEEDS with planned retirements in 2014-2015.

The locations of existing fossil units in EPA"s National Electric Energy Data System (NEEDS) v.5.13 are shown in Figure 2-3.

Figure 2-3.	Fossil Fuel-Fired Electricity Generating Facilities, by Size
Source: National Electric Energy Data System (NEEDS) v.5.13
Note: This map displays fossil capacity at facilities in the NEEDS v.5.13 IPM frame. NEEDS reflects available fossil capacity on-line by the end of 2015. This includes planned new builds already under construction and planned retirements. In areas with a dense concentration of facilities, some facilities may be obscured.

2.2.2 	Transmission
Transmission is the term used to describe the movement of electricity over a network of high voltage lines, from electric generators to substations where power is stepped down for local distribution. In the U.S. and Canada, there are three separate interconnected networks of high voltage transmission lines, each operating synchronously. Within each of these transmission networks, there are multiple areas where the operation of power plants is monitored and controlled to ensure that electricity generation and load are kept in balance. In some areas, the operation of the transmission system is under the control of a single regional operator; in others, individual utilities coordinate the operations of their generation, transmission, and distribution systems to balance their common generation and load needs.
2.2.3 	Distribution
Distribution of electricity involves networks of lower voltage lines and substations that take the higher voltage power from the transmission system and step it down to lower voltage levels to match the needs of customers. The transmission and distribution system is the classic example of a natural monopoly, in part because it is not practical to have more than one set of lines running from the electricity generating sources to substations or from substations to residences and businesses.
Transmission has generally been developed by the larger vertically integrated utilities that typically operate generation and distribution networks. Often distribution is handled by a large number of utilities that purchase and sell electricity, but do not generate it. Over the last couple of decades, several jurisdictions in the United States began restructuring the power industry to separate transmission and distribution from generation, ownership, and operation. As discussed below, electricity restructuring has focused primarily on efforts to reorganize the industry to encourage competition in the generation segment of the industry, including ensuring open access of generation to the transmission and distribution services needed to deliver power to consumers. In many states, such efforts have also included separating generation assets from transmission and distribution assets to form distinct economic entities. Transmission and distribution remain price-regulated throughout the country based on the cost of service.
2.3 	Sales, Expenses and Prices
These electric generating sources provide electricity for commercial, industrial and residential ultimate customers. Each of the three major ultimate categories consume roughly a quarter to a third of the total electricity produced (see Table 2-4). 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. The distribution between the end use categories changed very little between 2002 and 2012.
Table 2-4.	Total U.S. Electric Power Industry Retail Sales in 2012 (billion kWh)

Source: Table 2.2, EIA Electric Power Annual, 2013
Notes: Retail sales are not equal to net generation (Table 2-2) because net generation includes net exported electricity and loss of electricity that occurs through transmission and distribution.
Direct Use represents commercial and industrial facility use of onsite net electricity generation; and electricity sales or transfers to adjacent or co-located facilities for which revenue information is not available.
2.3.1	Electricity Prices
Electricity prices vary substantially across the United States, differing both between the ultimate customer categories and also by state and region of the country. Electricity prices are typically highest for residential and commercial customers because of the relatively high costs of distributing electricity to individual homes and commercial establishments. The high distribution costs are the result both of the necessary distribution network reaching to virtually every part of the country, and also that generating stations are increasingly located relatively far from population centers. Industrial customers generally pay the lowest average prices, reflecting both their proximity to generating stations and the fact that industrial customers receive electricity at higher voltages (which makes transmission more efficient and less expensive). Industrial customers frequently pay variable prices for electricity, varying by the season and time of day, while residential and commercial prices historically have been less variable. Overall industrial customer prices are usually considerable closer to the wholesale marginal cost of generating electricity than residential and commercial prices.
On a state-by-state basis, all retail electricity prices vary considerably. The Northeast, California and Alaska have average retail prices that can be as much as double those of other states (see Figure 2-4), and Hawaii has electricity.

Figure 2-4.	Average Retail Electricity Price by State (cents/kWh), 2011

Average national overall retail electricity prices increased between 2002 and 2012 by 36.7 percent in nominal (current year $) terms. The amount of increase differed for the three major end use categories (residential, commercial and industrial). National average residential prices increased the most (40.8 percent), and commercial prices increased the least (27.9 percent). The nominal year prices for 2002 through 2012 are shown in Figure 2-5.

Figure 2-5.	Nominal National Average Electricity Prices for Three Major End-Use Categories
Source: EIA AEO 2012, Table 2.4
Electricity prices for all three end-use categories increased more than overall inflation through this period, measured by either the GDP implicit price deflator (23.5 percent) or the consumer price index (CPI-U, which increased by 27.7 percent). Most of these electricity price increases occurred between 2002 and 2008; since 2008 nominal electricity prices have been relatively stable while overall inflation continued to increase. The increase in nominal electricity prices for the major end use categories, as well as increases in the GDP price and CPI-U indices for comparison, are shown in Figure 2-6.

Figure 2-6.	Relative Increases in Nominal National Average Electricity Prices for Major End-Use Categories, With Inflation Indices

The real (inflation-adjusted) change in average national electricity prices can be calculated using the GDP implicit price deflator. Figure 2-7 shows real (2011$) electricity prices for the three major customer categories from 1960 to 2012, and Figure 2-8 shows the relative change in real electricity prices relative to the prices in 1960. As can be seen in the figures, the price for industrial customers has always been lower than for either residential or commercial customers, but the industrial price has been more volatile. While the industrial real price of electricity in 2012 was relatively unchanged from 1960, residential and commercial real prices are 23% and 28% lower respectively than in 1960.

Figure 2-7.	Real National Average Electricity Prices (2011$) for Three Major End-Use Categories
Source: EIA Monthly Energy Review, April 2015, Table 9.8

Figure 2-8.	Relative Change in Real National Average Electricity Prices (2011$) for Three Major End-Use Categories
Source: EIA Monthly Energy Review, April 2015, Table 9.8
2.3.2	Prices of Fossil Fuels Used for Generating Electricity
Another important factor in the changes in electricity prices are the changes in fuel prices for the three major fossil fuels used in electricity generation; coal, natural gas and oil. Relative to real prices in 2002, the national average real price (in 2011$) of coal delivered to EGUs in 2012 had increased by 54 percent, while the real price of natural gas decreased by 22 percent. The real price of oil increased by 203 percent, but with oil declining as an EGU fuel (in 2012 oil generated only 1 percent of electricity) the doubling of oil prices had little overall impact in the electricity market. The combined real delivered price of all fossil fuels in 2012 increased by 23 percent over 2002 prices. Figure 2-9 shows the relative changes in real price of all 3 fossil fuels between 2002 and 2012.

Figure 2-9.	Relative Real Prices of Fossil Fuels for Electricity Generation; Change in National Average Real Price per MBtu Delivered to EGU
Source: EIA AEO 2012, Table 9.9
2.3.3	Changes in Electricity Intensity of the U.S. Economy Between 2002 to 2012
An important aspect of the changes in electricity generation (i.e., electricity demand) between 2002 and 2012 is that while total net generation increased by 4.9 percent over that period, the growth of generation is lower than both the population growth (9.2 percent) and real GDP growth (19.8 percent). Figure 2-10 shows the growth of electricity generation, population and real GDP during this period.

Figure 2-10.	Relative Growth of Electricity Generation, Population and Real GDP Since 2002
Sources: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All Sectors). U.S. Census.
Because electricity generation grew slower than both the population and GDP, the relative electric intensity of the U.S. economy improved (i.e., less electricity used per person and per real dollar of output) during 2002 to 2012. On a per capita basis, real GDP per capita grew by 10.9 percent, increasing from $44,900 (in 2011$) per person in 2002 to $49,800/person in 2012. At the same time electricity generation per capita decreased by 3.9 percent, declining from 13.4 MWh/person in 2002 to 12.8 MWh/person in 2012. The combined effect of these two changes improved the overall electricity efficiency of the U.S. market economy. Electricity generation per dollar of real GDP decreased 12.5 percent, declining from 299 MWh per $1 million of GDP to 261 MWh/$1 million GDP). These relative changes are shown in Figure 2-11. Figures 2-10 and 2-11 clearly show the effects of the 2007  -  2009 recession on both GDP and electricity generation, as well as the effects of the subsequent economic recovery.

Figure 2-11.	Relative Change of Real GDP, Population and Electricity Generation Intensity Since 2002
Sources: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All Sectors). U.S. Census
2.4 	Deregulation and Restructuring
The process of restructuring and deregulation of wholesale and retail electric markets has changed the structure of the electric power industry. In addition to reorganizing asset management between companies, restructuring sought a functional unbundling of the generation, transmission, distribution, and ancillary services the power sector has historically provided, with the aim of enhancing competition in the generation segment of the industry.
Beginning in the 1970s, government policy shifted against traditional regulatory approaches and in favor of deregulation for many important industries, including transportation (notably commercial airlines), communications, and energy, which were all thought to be natural monopolies (prior to 1970) that warranted governmental control of pricing. However, deregulation efforts in the power sector were most active during the 1990s. Some of the primary drivers for deregulation of electric power included the desire for more efficient investment choices, the economic incentive to provide least-cost electric rates through market competition, reduced costs of combustion turbine technology that opened the door for 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. Deregulation and market restructuring in the power sector involved the divestiture of generation from utilities, the formation of organized wholesale spot energy markets with economic mechanisms for the rationing of scarce transmission resources during periods of peak demand, the introduction of retail choice programs, and the establishment of new forms of market oversight and coordination.
The pace of restructuring in the electric power industry slowed significantly in response to market volatility in California and financial turmoil associated with bankruptcy filings of key energy companies. By the end of 2001, restructuring had either been delayed or suspended in eight states that previously enacted legislation or issued regulatory orders for its implementation (shown as "Suspended" in Figure 2-12). Eighteen other states that had seriously explored the possibility of deregulation in 2000 reported no legislative or regulatory activity in 2001 (EIA, 2003) ("Not Active" in Figure 2-12). Currently, there are 15 states plus the District of Columbia where price deregulation of generation (restructuring) has occurred ("Active" in Figure 2-12). Power sector restructuring is more or less at a standstill; by 2010 there were no active proposals under review by the Federal Energy Regulatory Commission (FERC) for actions aimed at wider restructuring, and no additional states have begun retail deregulation activity since that time.

Figure 2-12.	Status of State Electricity Industry Restructuring Activities
Source:	EIA 2010. "Status of Electricity Restructuring by State." Available at <http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html.
One major effect of the restructuring and deregulation of the power sector was a significant change in type of ownership of electricity generating units in the states that deregulated prices. Throughout most of the 20th century electricity was supplied by vertically integrated regulated utilities. The traditional integrated utilities generation, transmission and distribution in their designated areas, and prices were set by cost of service regulations set by state government agencies (e.g., Public Utility Commissions). Deregulation and restructuring resulted in unbundling of the vertical integration structure. Transmission and distribution continued to operate as monopolies with cost of service regulation, while generation shifted to a mix of ownership affiliates of traditional utility ownership and some generation owned and operated by competitive companies known as Independent Power Producers (IPP). The resulting generating sector differed by state or region, as the power sector adapted to the restructuring and deregulation requirements in each state.
By 2002 the major impacts of adapting to changes brought about by deregulation and restructuring during the 1990s were largely in place. The resulting ownership mix of generating capacity (MW) in 2002 was 62 percent of the generating capacity owned by traditional utilities, 35 percent owned by IPPs, and 3 percent owned by commercial and industrial producers. The mix of electricity generated (MWh) was more heavily weighted towards the utilities, with a distribution in 2002 of 66 percent, 30 percent and 4 percent for utilities, IPPs and commercial/industrial, respectively.
Since 2002 IPPs have expanded faster than traditional utilities, substantially increasing their share by 2012 of both capacity (58 percent utility, 39 percent IPPs, and 3 percent commercial/industrial) and generation (58 percent, 38 percent and 4 percent).
The mix of capacity and generation for each of the ownership types is shown in Figures 2-13 (capacity) and 2-14 (generation). The capacity and generation data for commercial and industrial owners are not shown on these figures due to the small magnitude of those ownership types. Figures 2-13 and 2-14 present the mixes in 2002 and 2012. A portion of the shift of capacity and generation is due to sales and transfers of generation assets from traditional utilities to IPPs, rather than strictly the result of newly built units.

Figures 2-13 and 2-14.	Capacity and Generation Mix by Ownership Type, 2002 & 2012

The mix of capacity by fuel types that have been built and retired between 2002 and 2012 also varies significantly by type of ownership. Figure 2-15 presents the new capacity built during that period, showing that IPPs built the majority of both new wind and solar generating capacity, as well as somewhat more natural gas capacity than the traditional utilities built. Figure 2-16 presents comparable data for the retired capacity, showing that utilities retired more coal and "other" capacity (mostly oil-fired) than IPPs retired, while the IPPs retired more natural gas capacity than the utilities retired. The retired gas capacity was primary (60%) steam and combustion turbines.

Figures 2-15 and 2-16.	Generation Capacity Built and Retired between 2002 and 2012 by Ownership Type

2.5	Emissions of Greenhouse Gases from Electric Utilities
The burning of fossil fuels, which generates about 69 percent of our electricity nationwide, results in emissions of greenhouse gases. The power sector is a major contributor of CO2 in particular, but also contributes to emissions of sulfur hexafluoride (SF6), CH4, and N2O. In 2013, the electricity generation accounted for 38 percent of national CO2 emissions. Including both generation and transmission (a source of SF6) and generation, the power sector accounted for 31 percent of total nationwide greenhouse gas emissions (measured in CO2 equivalent). Table 2-5 and Figure 2-17 show the CO2 emissions from the power sector relative to other major economic sectors. Table 2-6 shows the contributions of CO2 and other GHGs from the power and other major emitting economic sectors.

Table 2-5.	Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric tonnes of CO2 equivalent)

                                     2002
                                     2013
                          Change Between '02 and '13
                                 Sector/Source
                                 GHG Emissions
                             % Total GHG Emissions
                                 GHG Emissions
                             % Total GHG Emissions
                              Change in Emissions
                             % Change in Emissions
                        % of Total Change in Emissions
Electric Power Industry
                                                                          2,313
                                                                            33%
                                                                          2,077

                                                                            31%
                                                                           -236
                                                                           -10%
                                                                            64%
Transportation
                                                                          1,958
                                                                            28%
                                                                          1,806
                                                                            27%
                                                                           -151
                                                                            -8%
                                                                            41%
Industry
                                                                          1,419
                                                                            20%
                                                                          1,392
                                                                            21%
                                                                            -27
                                                                            -2%
                                                                             7%
Agriculture
                                                                            561
                                                                             8%
                                                                            587
                                                                             9%
                                                                             26
                                                                             5%
                                                                            -7%
Commercial
                                                                            365
                                                                             5%
                                                                            401
                                                                             6%
                                                                             37
                                                                            10%
                                                                           -10%
Residential
                                                                            374
                                                                             5%
                                                                            375
                                                                             6%
                                                                              1
                                                                             0%
                                                                             0%
US Territories
                                                                             52
                                                                        < 1%
                                                                             35
                                                                        < 1%
                                                                            -17
                                                                           -33%
                                                                             5%
Total Emissions
                                                                          7,041
                                                                           100%
                                                                          6,673
                                                                           100%
                                                                           -368
                                                                            -5%
                                                                           100%
Sinks and Reductions
                                                                           -885

                                                                           -882

                                                                              4
                                                                             0%

Net Emissions
                                                                          6,156

                                                                          5,791

                                                                           -368
                                                                            -6%

Source:	EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012", Table ES-6. Includes CO2, CH4, N2O and SF6 emissions.

Figure 2-17.	Domestic Emissions of Greenhouse Gases from Major Sectors, 2002 and 2013 (million metric tonnes of CO2 equivalent)
Source:	EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table ES-6

Table 2-6.	Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission and Distribution), 2002 and 2012 (million metric tonnes of CO2 equivalent)

                                     2002
                                     2013
                          Change Between '02 and '13
                            Gas/Fuel Type or Source
                                 GHG Emissions
                  % of Total GHG Emissions from Power Sector
                                 GHG Emissions
                  % of Total GHG Emissions from Power Sector
                              Change in Emissions
                             % Change in Emissions
CO2

                                                                          2,287
                                                                          98.9%
                                                                          2,052
                                                                          98.8%
                                                                           -235
                                                                           -10%

Fossil Fuel   Combustion
                                                                          2,273
                                                                          98.2%
                                                                          2,040
                                                                          98.2%
                                                                           -233
                                                                           -10%

Coal
                                                                          1,890
                                                                          81.7%
                                                                          1,575
                                                                          75.8%
                                                                           -315
                                                                           -17%

Natural Gas
                                                                            306
                                                                         13.22%
                                                                            442
                                                                         21.28%
                                                                            136
                                                                            45%

Petroleum
                                                                           76.8
                                                                          3.32%
                                                                           22.4
                                                                          1.08%
                                                                          -54.4
                                                                           -71%

Geothermal
                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%

Incineration of Waste
                                                                           11.8
                                                                          0.51%
                                                                           10.1
                                                                          0.49%
                                                                           -1.7
                                                                           -14%

Other Process Uses of Carbonates
                                                                            2.6
                                                                          0.11%
                                                                            2.2
                                                                          0.11%
                                                                           -0.4
                                                                           -15%
CH4

                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%

Stationary Combustion*
                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%

Incineration of Waste
                                                                              +

                                                                             +

N2O

                                                                           12.4
                                                                          0.54%
                                                                           19.4
                                                                          0.93%
                                                                            7.0
                                                                            56%

Stationary Combustion*
                                                                           12.0
                                                                          0.52%
                                                                           19.1
                                                                          0.92%
                                                                            7.1
                                                                            59%

Incineration of Waste
                                                                            0.4
                                                                          0.02%
                                                                            0.3
                                                                          0.01%
                                                                           -0.1
                                                                           -25%
SF6

                                                                           13.3
                                                                          0.57%
                                                                            5.1
                                                                          0.25%
                                                                           -8.2
                                                                           -62%

Electrical Transmission and Distribution
                                                                           13.3
                                                                          0.57%
                                                                            5.1
                                                                          0.25%
                                                                           -8.2
                                                                           -62%
                              Total GHG Emissions
                                                                          2,313

                                                                          2,064

                                                                           -236
                                                                           -10%
Source:	EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-11
* Includes only stationary combustion emissions related to the generation of electricity.
** SF6 is not covered by this rule, which specifically regulates GHG emissions from combustion.
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
The amount of CO2 emitted during the combustion of fossil fuels varies according to the carbon content and heating value of the fuel used. The CO2 emission factors used in IPM v5.14 (same as used in v5.13) are shown in Table 2-7. Coal has higher carbon content than oil or natural gas, and thus releases more CO2 during combustion. Coal emits around 1.7 times as much carbon per unit of energy when burned as natural gas (EPA 2013).

Table 2-7.	Fossil Fuel Emission Factors in EPA Base Case 5.14 IPM Power Sector Modeling Application
Fuel Type
Carbon Dioxide (lbs/MMBtu)
Coal

   Bituminous
               202.8  -  209.6
   Subbituminous
               209.2  -  215.8
   Lignite
               212.6  -  219.
Natural Gas
                                     117.1
Fuel Oil

   Distillate
                                     161.4
   Residual
                                161.4  -  173.9
Biomass
                                      195
Waste Fuels

   Waste Coal
                                     204.7
   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.5.13, Table 11-5. The emission factors used in Base Case 5.14 are identical to the emission factors in IPM Base Case 5.13.
Note:	CO2 emissions presented here for biomass account for combustion only and do not reflect lifecycle emissions from initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon source).
2.6 	Carbon Dioxide Control Technologies
In the power sector, current approaches available for significantly reducing the CO2 emissions of new fossil fuel combustion sources intended for intermediate and baseload operations include the use of: carbon capture and storage (CCS), higher-efficiency designs (e.g., supercritical or ultrasupercritical steam units, integrated gasification combined cycle (IGCC), or combined-cycle combustion-turbine/steam-turbine units), and/or lower-emitting fuels (e.g. natural gas rather than coal).
Daily peak electricity demands, involving operation for relatively few hours per year, are often most economically met by simple-cycle combustion turbines (CT). Stationary CTs used for power generation can be installed quickly, at relatively low capital cost. They can be remotely started and loaded quickly, and can follow rapid demand changes. Full-load efficiencies of large current technology CTs are 30-33 percent (high heating value basis), as compared to efficiencies of 50 percent or more for new combined-cycle units that recover and use the exhaust heat otherwise wasted from a CT . A simple-cycle CT's lower efficiency causes it to burn much more fuel to produce a MWh of electricity than a combined-cycle unit. Thus, when burning natural gas its CO2 emission rate per MWh could be 40-60 percent higher than a more efficient NGCC unit.
Baseload electricity demand can be met with NGCC generation, coal and other fossil-fired steam generation, and IGCC technology, as well as generation from sources that do not emit CO2, such as nuclear and hydro. IGCC employs the use of a gasifier to transform fossil fuels into synthesis gas ("syngas") and heat. The syngas is used to fuel a combined cycle generator, and the heat from the syngas conversion can produce steam for the steam turbine portion of the combined cycle generator. Electricity can be generated through this IGCC process somewhat more efficiently than through conventional boiler-steam generators. Additionally, with gasification, some of the syngas can be converted into other marketable products such as fertilizer, and CO2 can be captured for use in EOR.
2.6.1 	Carbon Capture and Storage
CCS can be achieved through either pre-combustion or post-combustion capture of CO2 from a gas stream associated with the fuel combusted. Furthermore, CCS can be designed and operated for full capture of the CO2 in the gas stream (i.e., above 90 percent) or for partial capture (below 90 percent). For post-combustion capture, CO2 is stripped from the flue gas by passing the flue gas through a liquid absorbent which selectively reacts with the gaseous carbon dioxide to remove it from the combustion gas stream. The absorbent, upon saturation, transfers to a downstream operation which regenerates the absorbent by desorbing the CO2 back to gaseous form. The absorbent recycles back into the process to repeat the capture cycle while the removed carbon dioxide is compressed, sent to storage and sequestered. This process is illustrated for a pulverized coal power plant in Figure 2-18. For post-combustion, a station's net generating output could be 20-30 percent lower due to the energy needs of the capture process.

Figure 2-18.	Post-Combustion CO2 Capture for a Pulverized Coal Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010

Pre-combustion capture is mainly applicable to IGCC facilities, where the fuel is converted into gaseous components ("syngas") under heat and pressure and some percentage of the carbon contained in the syngas is captured before combustion. For pre-combustion technology, a significant amount of energy is needed to gasify the fuel(s). This process is illustrated in Figure 2-18. Application of post-combustion CCS with IGCC can be designed to use no water-gas shift, or single- or two-stage shift processes, to obtain varying percentages of CO2 removal  -  from a "partial capture" percentage to 90 percent "full capture." Pre-combustion CCS typically has a lesser impact on net energy output than does post-combustion CCS. For more detail on CCS technology, see the "Report of the Interagency Task Force on Carbon Capture and Storage" (2010).

Figure 2-18.	Pre-Combustion CO2 Capture for an IGCC Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010

Carbon capture technology has been successfully applied since 1930 on several smaller scale industrial facilities and more recently in a number of demonstration phase projects worldwide for power sector applications. In October 2014 the first industrial-scale coal capture and storage demonstration project for electricity generation began operation at the Boundary Dam Power Station in Saskatchewan, Canada. The Boundary Dam CCS project is the first industrial-scale electric power project in the world to begin operation. Boundary Dam Station is owned by the Province of Saskatchewan, and operated by SaskPower, a provincially owned corporation that is the primary electric utility in the Province. The demonstration project retrofit Unit 3 (a 130 MW, coal fired built in 1970, and rebuilt in 2013) at a total cost of approximately $1.5 billion (Canadian, or about $1.2 billion US), including a partial subsidy of $240 million (Canadian) by the Canadian federal government. The carbon capture system is a post-combustion process designed to capture 90 percent of the CO2 emitted by Unit #3. Retrofitting the carbon capture system reduced the capacity of the unit to 110 MW. The majority of the captured CO2 is used for an EOR project in southern Saskatchewan. The portion of the CO2 is being stored in a nearby research and monitoring geological storage facility, where the captured CO2 will be injected 3.4 kilometers underground into a sandstone formation located below the major coal field supplying lignite to Unit # 3. The remaining captured CO2 will be injected into deep saline formations.
In the United States the Kemper County Carbon Dioxide Capture and Storage Project in Mississippi. Construction began in 2010, and the startup is currently scheduled for May, 2016. The Kemper County CCS project is constructing a new 524 MW lignite unit as well as a 58 MW natural gas unit. Mississippi Power (a division of Southern Power) is building and will operate the Kemper County project. The control system is designed to capture 65 percent of the CO2 generated by the plant, and is projected to capture 3.5 million tons of CO2 per year. The resulting CO2 emission rate is expected to ~800 pounds per MWh produced. The current total cost estimate is $5.6 billion, a substantial increase from the original $2.4 billion estimate. The construction has received a $270 million grant from the US Department of Energy, and $133 million in investment tax credits from the Internal Revenue Service. The captured CO2 will be transported via a 60 mile pipeline and used for EOR projects in mature Mississippi oil fields.
The only other industrial-scale electricity power sector CCS project currently under construction is the W.A. Parish Petra Nova CCS Project near Houston, Texas. The Parish Petra project is a 50/50 partnership between NRG Energy (an integrated electricity company generating and supplying electricity to 1.6 million customers in Texas) and the Nippon Oil and Gas Exploration Company. The Parish project will retrofit a post-combustion CCS system on a portion of the flue gas from the existing 610 MW coal fired Unit # 8. The CCS system will treat a 240 MW slipstream of the flue gas, and is designed to capture 90 percent of the CO2 in the treated flue gas. The capacity rating of Unit # 8 will not be reduced due to the CCS project because an 85 MW custom-built natural gas fired combustion turbine co-generation unit is being built on-site to provide both electricity and steam to the CCS unit. The total cost of the CCS project is estimated to be $1 billion (including a $167 million grant from the US Department of Energy), and is expected to extract 1.4  -  1.6 million tons of CO2 per year. The construction contract was awarded in July, 2014, and operation is expected to begin in early 2016. The CO2 will be piped 85 miles to a reservoir for EOR in the West Ranch Oil Field.
2.6.2 	Geologic and Geographic Considerations for Geologic Sequestration
Geologic sequestration (GS) (i.e., long-term containment of a CO2 stream in subsurface geologic formations) is technically feasible and available throughout most of the United States. GS is feasible in different types of geologic formations including deep saline formations (formations with high salinity formation fluids) or in oil and gas formations, such as where injected CO2 increases oil production efficiency through a process referred to as enhanced oil recovery (EOR). CO2 may also be used for other types of enhanced recovery, such as for natural gas production. Reservoirs, such as un-mineable coal seams, also offer the potential for geologic storage. The geographic availability of deep saline formations, EOR, and un-mineable coal seams is shown in Figure 2-14. Estimates of CO2 storage resources by state compiled by the DOE's National Carbon Sequestration Database and Geographic Information System (NATCARB) and published in a Carbon Utilization and Storage Atlas (discussed below) are provided in Table 2-8.

Figure 2-19.	Geologic Sequestration in the Continental United States
Source: EPA 2013: Data sources: EPA's Greenhouse Gas Reporting Program; Department of Energy, NATCARB; Department of Transportation, National Pipeline Management System.

Table 2-8.	Total CO2 Storage Resource

                             Million Metric Tons*
                                     State
                                 Low Estimate
                                 High Estimate
Alabama
                                    122,490
                                    694,380
Alaska
                                     8,640
                                    19,750
Arizona
                                      130
                                     1,170
Arkansas
                                     6,180
                                    63,670
California
                                    33,890
                                    420,630
Colorado
                                    37,610
                                    357,190
Connecticut
                                 not assessed
                                 not assessed
Delaware
                                      40
                                      40
District of Columbia
                                 not assessed
                                 not assessed
Florida
                                    102,740
                                    555,010
Georgia
                                    145,340
                                    159,050
Hawaii
                                 not assessed
                                 not assessed
Idaho
                                      40
                                      390
Illinois
                                    10,020
                                    116,820
Indiana
                                    32,020
                                    68,210
Iowa
                                      10
                                      50
Kansas
                                    10,880
                                    86,340
Kentucky
                                     2,920
                                     7,650
Louisiana
                                    169,500
                                   2,103,980
Maine
                                 not assessed
                                 not assessed
Maryland
                                     1,860
                                     1,930
Massachusetts
                                 not assessed
                                 not assessed

Table 2-8. 	Total CO2 Storage Resource, continued

                             Million Metric Tons*
                                     State
                                 Low Estimate
                                 High Estimate
Michigan
                                    19,050
                                    47,210
Minnesota
                                 not assessed
                                 not assessed
Mississippi
                                    145,010
                                   1,185,030
Missouri
                                      10
                                      170
Montana
                                    84,580
                                    912,720
Nebraska
                                    23,770
                                    113,240
Nevada
                                 not assessed
                                 not assessed
New Hampshire
                                 not assessed
                                 not assessed
New Jersey
                                       0
                                       0
New Mexico
                                    42,760
                                    359,090
New York
                                     4,640
                                     4,640
North Carolina
                                     1,340
                                    18,390
North Dakota
                                    67,090
                                    147,480
Offshore Federal Only
                                    489,840
                                   6,440,090
Ohio
                                    13,460
                                    13,460
Oklahoma
                                    56,950
                                    244,550
Oregon
                                     6,810
                                    93,700
Pennsylvania
                                    22,100
                                    22,100
Rhode Island
                                 not assessed
                                 not assessed
South Carolina
                                    30,100
                                    34,180
South Dakota
                                     8,760
                                    24,030
Tennessee
                                      430
                                     3,860
Texas
                                    443,800
                                   4,329,930
Utah
                                    25,470
                                    240,910
Vermont
                                 not assessed
                                 not assessed
Virginia
                                      440
                                     2,910
Washington
                                    36,620
                                    496,730
West Virginia
                                    16,650
                                    16,650
Wisconsin
                                       0
                                       0
Wyoming
                                    72,690
                                    684,850
U.S. Total
                                   2,296,680
                                  20,092,180
* States with a "zero" value represent estimates of minimal CO2 storage resource. States that have not yet been assessed by the RCSPs have been identified.

2.7.2 	Availability of geologic sequestration in deep saline formations
DOE and the United States Geological Survey (USGS) have independently conducted preliminary analyses of the availability and potential CO2 sequestration capacity of deep saline formations in the United States. DOE estimates are compiled by the DOE's National Carbon Sequestration Database and Geographic Information System (NATCARB) using volumetric models and published in a Carbon Utilization and Storage Atlas. DOE estimates that areas of the United States with appropriate geology have a sequestration potential of at least 2,035 billion metric tons of CO2 in deep saline formations. According to DOE and at least 39 states have geologic characteristics that are amenable to deep saline GS in either onshore or offshore locations. In 2013, the USGS completed its evaluation of the technically accessible GS resources for CO2 in U.S. onshore areas and state waters using probabilistic assessment. The USGS estimates a mean of 3,000 billion metric tons of subsurface CO2 sequestration potential, including saline and oil and gas reservoirs, across the basins studied in the United States. As shown in Figure 2-14, there are 39 states for which onshore and offshore deep saline formation storage capacity has been identified.
2.7.3	Availability of CO2 storage via enhanced oil recovery (EOR)
Although the regulatory impact analysis for this rule relies on GS in deep saline formations, the EPA also recognizes the potential for securely sequestering CO2 via EOR. EOR has been successfully used at numerous production fields throughout the United States to increase oil recovery. The oil industry in the United States has over 40 years of experience with EOR. An oil industry study in 2014 identified more than 125 EOR projects in 98 fields in the United States. More than half of the projects evaluated in the study have been in operation for more than 10 years, and many have been in operation for more than 30 years. This experience provides a strong foundation for demonstrating successful CO2 injection and monitoring technologies, which are needed for safe and secure GS that can be used for deployment of CCS across geographically diverse areas.
Currently, 12 states have active EOR operations and most have developed an extensive CO2 infrastructure, including pipelines, to support the continued operation and growth of EOR. An additional 23 states are within 150 miles of current EOR operations. See Figure 2-14. The vast majority of EOR is conducted in oil reservoirs in the Permian Basin, which extends through southwest Texas and southeast New Mexico. States where EOR is utilized include Alabama, Colorado, Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming.
At the project level, the volume of CO2 already injected for EOR and the duration of operations are of similar magnitude to the duration and volume of CO2 expected to be captured from fossil fuel-fired EGUs. The volume of CO2 used in EOR operations can be large (e.g., 55 million tons of CO2 were stored in the SACROC unit in the Permian Basin over 35 years), and operations at a single oil field may last for decades, injecting into multiple parts of the field. According to data reported to the EPA's Greenhouse Gas Reporting Program (GHGRP), approximately 60 million metric tons of CO2 were supplied to EOR in the United States in 2013. Approximately 70 percent of this total CO2 supplied was produced from natural (geologic) CO2 sources, and approximately 30 percent was captured from anthropogenic sources.
A DOE-sponsored study has analyzed the geographic availability of applying EOR in 11 major oil producing regions of the United States and found that there is an opportunity to significantly increase the application of EOR to areas outside of current operations. DOE-sponsored geologic and engineering analyses show that expanding EOR operations into areas additional to the capacity already identified and applying new methods and techniques over the next 20 years could utilize 18 billion metric tons of anthropogenic CO2 and increase total oil production by 67 billion barrels. The availability of anthropogenic CO2 in areas outside of current sources could drive new EOR projects by making more CO2 locally available.
2.8	GHG and Clean Energy Regulation in the Power Sector
2.8.1 	State Policies
Several states have also established emission performance standards or other measures to limit emissions of GHGs from new EGUs that are comparable to this rulemaking.
In 2003, then-Governor George Pataki sent a letter to his counterparts in the Northeast and Mid-Atlantic inviting them to participate in the development of a regional cap-and-trade program addressing power plant CO2 emissions. This program, known as the Regional Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional CO2 cap for participating states. The currently participating states include: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. The cap covers CO2 emissions from all fossil-fired EGUs greater than 25 MW in participating states, and limits total emissions to 91 million short tons in 2014. The 2014 emissions cap is a 51 percent reduction below the initial cap in 2009 to 2011 of 188 million tons. This emissions budget is reduced 2.5 percent annually from 2015 to 2020. RGGI CO2 allowances are sold in a quarterly auction. RGGI conducted their 27[th] quarterly allowance auction in March, 2015 the market clearing price was $5.41 per ton of CO2 for current allowances, which was a record high price (the February '15 price of $5.21 was the previous record). A total of allowances for 15.3 million tons were sold in the March '15 auction, well below the record of 38.7 million tons sold in June '13 for $3.21. The RGGI CO2 emissions cap was reduced from 188 million tons (in a 10 state region) in 2009-2011, and reduced again to 165 million tons (in a 9 state region) in 2012-2014. The cap is further reduced by 2.5 percent each year from 2014 through 2020.
In September 2006, California Governor Schwarzenegger signed into law Senate Bill 1368. The law limits long-term investments in baseload generation by the state's utilities to power plants that meet an emissions performance standard jointly established by the California Energy Commission and the California Public Utilities Commission. The Energy Commission has designed regulations that establish a standard for new and existing baseload generation owned by, or under long-term contract to publicly owned utilities, of 1,100 lb CO2/MWh.
In 2006 Governor Schwarzenegger also signed into law Assembly Bill 32, the Global Warming Solutions Act of 2006. This act includes a multi-sector GHG cap-and-trade program which covers approximately 85 percent of the state GHG emissions. EGUs are includes in phase I of the program, which began in 2013. Phase II begins in 2020 and includes upstream sources. The cap is based on a 2 percent reduction from total 2012 expected emissions, and declines 2 percent annually through 2014, then 3 percent each year until 2020. The AB32 cap and trade program began functioning in 2011, and functioning market is now operating on the NYMEX futures commodity market. The final 2014 market price for 2014 carbon allowances was $12.38/tonne of carbon. On April 17, 2015 the 2015 allowance futures price was $12.65/tonne, and the spot price was $12.46/tonne.
In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, which established statewide GHG emissions reduction goals, and imposed an emission standard that applies to any baseload electric generation that commenced operation after June 1, 2008 and is located in Washington, whether or not that generation serves load located within the state. Baseload generation facilities must initially comply with an emission limit of 1,100 lb CO2/MWh.
In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that facilities generating baseload electricity, whether gas- or coal-fired, must have emissions equal to or less than 1,100 lb CO2/MWh, and prohibited utilities from entering into long-term purchase agreements for baseload electricity with out-of-state facilities that do not meet that standard. Natural gas- and petroleum distillate-fired facilities that are primarily used to serve peak demand or to integrate energy from renewable resources are specifically exempted from the performance standard.
In August 2011, New York Governor Cuomo signed the Power NY Act of 2011. This regulation establishes CO2 emission standards for new and modified electric generators greater than 25 MW. The standards vary based on the type of facility: baseload facilities must meet a CO2 standard of 925 lb/MWh or 120 lb/MMBtu, and peaking facilities must meet a CO2 standard of 1,450 lbs/MWh or 160 lbs/MMBtu.
Additionally, most states have implemented Renewable Portfolio Standards (RPS), or Renewable Electricity Standards (RES). These programs are designed to increase the renewable share of a state's total electricity generation. Currently 30 states and the District of Columbia have enforceable RPS or other mandatory renewable capacity policies, and 7 states have voluntary goals. These programs vary widely in structure, enforcement, and scope.
2.8.2 	Federal Policies
In April 2007, the Supreme Court concluded that GHGs met the CAA definition of an air pollutant, giving the EPA the authority to regulate GHGs under the CAA contingent upon an agency determination that GHG emissions from new motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. This decision to regulate GHG emissions for motor vehicles set the stage for the determination of whether other sources of GHG emissions, including stationary sources, would need to be regulated as well.
In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; Public Law 110 - 161), the EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 5620) which required reporting of GHG data and other relevant information from fossil fuel suppliers and industrial gas suppliers, direct greenhouse gas emitters, and manufacturers of heavy-duty and off-road vehicles and engines. The purpose of the rule was to collect accurate and timely GHG data to inform future policy decisions. As such, it did not require that sources control greenhouse gases, but sources above certain threshold levels must monitor and report emissions.
In August 2007, the EPA issued a prevention of significant deterioration (PSD) permit to Deseret Power Electric Cooperative, authorizing it to construct a new waste-coal-fired EGU near its existing Bonanza Power Plant, in Bonanza, Utah. The permit did not include emissions control requirements for CO2. The EPA acknowledged the Supreme Court decision, but found that decision alone did not require PSD permits to include limits on CO2 emissions. Sierra Club challenged the Deseret permit. In November 2008, the Environmental Appeals Board (EAB) remanded the permit to the EPA to reconsider "whether or not to impose a CO2 BACT (best available control technology) 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 indicating that the PSD Permitting Program would apply to pollutants that are subject to either a provision in the CAA or a regulation adopted by the EPA under the CAA that requires actual control of emissions of that pollutant. The memo further explained that pollutants for which the EPA regulations only require monitoring or reporting, such as the provisions for CO2 in the Acid Rain Program, are not subject to PSD permitting. Fifteen organizations petitioned the EPA for reconsideration, prompting the agency to issue a revised finding in March 2009. After reviewing comments, the EPA affirmed the position that PSD permitting is not triggered for a pollutant such as GHGs until a final nationwide rule requires actual control of emissions of the pollutant. For GHGs, this meant January 2011 when the first national rule limiting GHG emissions for cars and light trucks was scheduled to take effect. Therefore, a permit issued after January 2, 2011, would have to address GHG emissions.
The Administrator signed two distinct findings in December 2009 regarding greenhouse gases under section 202(a) of the Clean Air Act. The endangerment finding indicated that current and projected concentrations of the six key well-mixed greenhouse gases  -- CO2, CH4, N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and SF6  --  in the atmosphere threaten the public health and welfare of current and future generations. These greenhouse gases have long lifetimes and, as a result, become homogeneously distributed through the lower level of the Earth's atmosphere (IPCC, 2001). This differentiates them from other greenhouse gases that are not homogeneously distributed in the atmosphere. The cause and contribute finding indicated that the combined emissions of these well-mixed greenhouse gases from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas pollution which threatens public health and welfare. Both findings were published in the Federal Register on December 15, 2009 (Docket ID EPA-HQ-OAR-2009-0171). These findings did not themselves impose any requirements on any industry or other entities, but allowed the EPA to regulate greenhouse gases under the CAA (see preamble section II.E for regulatory background). This action was a prerequisite to implementing the EPA's proposed greenhouse gas emission standards for light-duty vehicles, which was finalized in January 2010. Once a pollutant is regulated under the CAA, it is subject to permitting requirements under the PSD and Title V programs. The 2009 Endangerment Finding and a denial of reconsideration were challenged in a lawsuit; on June 26, 2012, the DC Circuit Court upheld the Endangerment Finding and the Reconsideration Denial, ruling that the Finding was neither arbitrary nor capricious, was consistent with Massachusetts v. EPA, and was adequately supported by the administrative record. The Court found that the EPA had based its decision on "substantial scientific evidence," noted that the EPA's reliance on assessments was consistent with the methods decision-makers often use to make a science-based judgment, and stated that "EPA's interpretation of the governing CAA provisions is unambiguously correct."
In May 2010, the EPA issued the final Tailoring Rule which set thresholds for GHG emissions that define when permits under the New Source Review and Title V Operating Permit programs are required for new and existing industrial facilities. Facilities responsible for nearly 70 percent of the national GHG emissions from stationary sources, including EGUs, were subject to permitting requirements under the rule. This rule was upheld by the D.C. Circuit in 2012.
The EPA entered into a proposed settlement agreement in December 2010 to issue rules that will address greenhouse gas emissions from fossil fuel-fired power plants. On March 27, 2012, EPA proposed NSPS for CO2 emissions from new source natural gas, coal, and other solid fossil-fired EGUs. After consideration of information provided in more than 2.7 million comments on the March 27, 2012 proposal, as well as consideration of continuing changes in the electricity sector, the EPA determined that revisions in its initially proposed approach were warranted. EPA replaced that prior proposal with a new proposal for NSPS for CO2 emissions from EGUs on September 20, 2013; this action finalizes that rulemaking. Existing source standards are not addressed in this action. Details of the settlement agreement can be found on the EPA website.
2.9 	Revenues and Expenses
Due to lower retail electricity sales, total utility operating revenues declined in 2012 to $271 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008 levels in 2012, operating expenses were appreciably lower and as a result, net income also rose in comparison to 2008 (see Table 2-9). 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. In 2012 electricity generation was 1.28 percent below the generation in 2011, and has declined in 4 of the past 5 years.
Table 2-9 shows that investor-owned utilities (IOUs) earned income of about 13.0 percent compared to total revenues in 2012. The 2012 return on revenue was the third highest year for the period 2002 to 2012 (average: 11.9 percent range: 10.6 percent to 13.32 percent).

Table 2-9.	Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities for 2010 (nominal $millions)

2002

2008

2012
Utility Operating Revenues
                                    219,609
                                    298,962
                                    270,912
Electric Utility
                                    200,360
                                    266,124
                                    249,166
Other Utility
                                    19,250
                                    32,838
                                    21,745
Utility Operating Expenses
                                    189,062
                                    267,263
                                    235,694
Electric Utility
                                    171,604
                                    236,572
                                    220,722
      Operation
                                    116,660
                                    175,887
                                    152,379
         Production
                                    90,715
                                    140,974
                                    111,714
            Cost of Fuel
                                    24,149
                                    47,337
                                    38,998
            Purchased Power
                                    58,810
                                    84,724
                                    54,570
            Other
                                     7,776
                                     8,937
                                    18,146
      Transmission
                                     3,560
                                     6,950
                                     7,183
      Distribution
                                     3,117
                                     3,997
                                     4,181
      Customer Accounts
                                     4,168
                                     5,286
                                     5,086
      Customer Service
                                     1,820
                                     3,567
                                     5,640
      Sales
                                      264
                                      225
                                      221
      Admin. and
      General
                                    13,018
                                    14,718
                                    18,353
      Maintenance
                                    10,861
                                    14,192
                                    15,489
      Depreciation
                                    16,199
                                    19,049
                                    23,677
      Taxes and Other
                                    26,716
                                    26,202
                                    29,177
       Other Utility
                                    17,457
                                    30,692
                                    14,972
Net Utility Operating Income
                                    30,548
                                    31,699
                                    35,218
Source: Table 8.3, EIA Electric Power Annual, 2012
Note: This data does not include information for public utilities, nor for Independent Power Producers (IPPs).
2.10 	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 period last decade, the annual average nominal price of gas delivered to the power sector have ranged from $3.42/MMBtu (in 2012) to $9.02/MMBtu (in 2008). During that time, the daily price of natural gas reached as high as $18.48/MMBtu and as low as $2.03.  Adjusting for inflation using the GDP implicit price deflator, in $2011 the annual average price of natural gas delivered to the power sector ranged from $9.38 (in 2008) to $3.36 (in 2012). The annual natural gas prices in both nominal and real (2011$) terms are in Figure 2-20. A comparison of the trends in the real price of natural gas with the real price of delivered coal and oil are shown in Figure 2-21. Figure 16 shows that while the real price of coal and oil increased from 2002 to 2012 (+54 percent and +203 percent respectively), the real price of natural gas declined by 22 percent in the same period. Most of the decline in real natural gas prices occurred between 2008 (the peak price year) and 2012, during which real gas prices declined by 64 percent while coal and oil prices both increased by 9 percent. The sharp decline in natural gas prices from 2008 to 2012 was primarily caused by the rapid increase in natural gas production from shale formations.

Figure 2-20.	Relative Change Nominal and Real (2011$) Prices of Natural Gas Delivered to the Power Sector ($/MMBtu)
Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.

Figure 2-21.	Relative Change in Real (2011$) Prices of Fossil Fuels Delivered to the Power Sector ($/MMBtu)
Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.

Current and projected natural gas prices are considerably lower than the prices observed over the past decade, largely due to advances in hydraulic fracturing and horizontal drilling techniques that have opened up new shale gas resources and substantially increased the supply of economically recoverable natural gas. According to AEO 2012 (EIA 2012):
      Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States.
The U.S. Energy Information Administration's Annual Energy Outlook 2014 estimates that the United States possessed 2,266 trillion cubic feet (Tcf) of technically recoverable dry natural gas resources as of January 1, 2012. Proven reserves make up 15 percent of the technically recoverable total estimate, with the remaining 85 percent from unproven reserves. Natural gas from proven and unproven shale resources accounts for 611 Tcf of this resource estimate.
Many shale formations, especially the Marcellus, are so large that only small portions of the entire formations have been intensively production-tested. Furthermore, estimates from the Marcellus and other emerging fields with few wells already drilled are likely to shift significantly over time as new geological and production information becomes available. Consequently, the estimate of technically recoverable resources is highly uncertain, and is regularly updated as more information is gained through drilling and production.
At the 2012 rate of U.S. consumption (about 25.6 Tcf per year), 2,266 Tcf of natural gas is enough to supply nearly 90 years of use. The AEO 2014 estimate of the shale gas resource base is modestly higher than the AEO 2012 estimate (2,214 Tcf) shale gas production estimates, driven by lower drilling costs and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher value in energy equivalent terms than dry natural gas.
EIA's projections of natural gas conditions did not change substantially in AEO 2014 from either the AEO 2012 or 2013, and EIA is still forecasting abundant reserves consistent with the above findings. Recent historical data reported to EIA is also consistent with these trends, with 2014 being the highest year on record for domestic natural gas production.
2.11 	References