3,757
                                    63,254
                                    56,781
Natural Gas
                                     5,470
                                    459,803
                                    401,272
Other Gases
                                      98
                                     2,218
                                     1,932
Nuclear
                                      104
                                    106,618
                                    101,004
Hydroelectric Conventional
                                     4,005
                                    77,910
                                    78,518
Wind
                                      620
                                    34,683
                                    34,296
Solar Thermal and Photovoltaic
                                      110
                                      640
                                      619
Wood and Wood Derived Fuels
                                      353
                                     7,829
                                     6,939
Geothermal
                                      222
                                     3,421
                                     2,382
Other Biomass
                                     1,502
                                     5,007
                                     4,317
Pumped Storage
                                      151
                                    20,538
                                    22,160
Other
                                      48
                                     1,042
                                      888
Total
                                    17,876
                                   1,121,686
                                   1,025,400
Source: EIA Electric Power Annual 2009, Table 1.2
      These electric generating sources provide electricity for commercial, industrial, and residential uses, each of which consumes roughly a quarter to a third of the total electricity produced (see Table 6-2).  Some of these uses are highly variable, such as heating and air conditioning in residential and commercial buildings, while others are relatively constant, such as industrial processes that operate 24 hours a day.
Table 6-2.  Total U.S. Electric Power Industry Retail Sales in 2009 (Billion kWh)

                        Sales/Direct Use (Billion kWh)
                            Share of Total End Use
Retail Sales
Residential
                                     1,364
                                      37%

Commercial
                                     1,307
                                      35%

Industrial
                                      917
                                      25%

Transportation
                                       8
                                     0.2%
Direct Use
                                      127
                                      3%
Total End Use
                                     3,724
                                     100%
Source:  EIA Electric Power Annual 2009, Table 7.2
      In 2009, electric generating sources produced 3,950 billion kWh to meet electricity demand.  Roughly 70 percent of this electricity was produced through the combustion of fossil fuels, primarily coal and natural gas, with coal accounting for almost half of the total (see Table 6-3).
Table 6-3.  Electricity Net Generation in 2009 (Billion kWh)

                         Net Generation (Billion kWh)
                               Fuel Source Share
Coal
                                     1,756
                                     44.5%
Petroleum
                                      39
                                     1.0%
Natural Gas
                                      921
                                     23.3%
Other Gases
                                      11
                                     0.3%
Nuclear
                                      799
                                     20.2%
Hydroelectric
                                      273
                                     6.9%
Other
                                      151
                                     3.8%
Total
                                     3,950
                                     100%
Source: EIA Electric Power Annual 2009, Table 1.1
Note: Retail sales and net generation are not equal because net generation includes net exported electricity and loss of electricity that occurs through transmission and distribution.

      Coal-fired generating units typically supply "base-load" electricity, the portion of electricity loads which are continually present, and typically operate throughout the day.  Along with nuclear generation, these coal units meet the part of demand that is relatively constant.  Although much of the coal fleet operates as base load, there can be notable differences across various facilities (see Table 6-4).  For example, coal-fired units less than 100 MW in size comprise 37 percent of the total number of coal-fired units, but only 6 percent of total coal-fired capacity.  Gas-fired generation is better able to vary output and is the primary option used to meet the variable portion of the electricity load and typically supplies "peak" power, when there is increased demand for electricity (for example, when businesses operate throughout the day or when people return home from work and run appliances and heating/air-conditioning), versus late at night or very early in the morning, when demand for electricity is reduced.

Table 6-4.  Coal Steam Electricity Generating Units, by Size, Age, Capacity, and Efficiency (Heat Rate)
                            Unit Size Grouping (MW)

                                   No. Units
                                % of All Units
                                   Avg. Age
                         Avg. Net Summer Capacity (MW)
                        Total Net Summer Capacity (MW)
                               % Total Capacity
                           Avg. Heat Rate (Btu/kWh)
0
to
25

                                      193
                                      15%
                                      45
                                      15
                                     2,849
                                      1%
                                    11,154
>25
to
49

                                      108
                                      9%
                                      42
                                      38
                                     4,081
                                      1%
                                    11,722
50
to
99

                                      162
                                      13%
                                      47
                                      75
                                    12,132
                                      4%
                                    11,328
100
to
149

                                      269
                                      21%
                                      49
                                      141
                                    38,051
                                      12%
                                    10,641
150
to
249

                                      81
                                      6%
                                      43
                                      224
                                    18,184
                                      6%
                                    10,303
250
and up

                                      453
                                      36%
                                      34
                                      532
                                    241,184
                                      76%
                                    10,193
Totals

                                     1,266

                                    316,480

Source: National Electric Energy Data System (NEEDS) v.4.10
Notes: A lower heat rate indicates a higher level of efficiency. Table is limited to coal-steam units online in 2010 or earlier, and excludes those units with planned retirements.

Figure 6-1.  Fossil Fuel-Fired Electricity Generating Facilities, by Size

Notes/Source: National Electric Energy Data System (NEEDS 4.10) (EPA, December 2010).  This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capacity on-line by the end of 2011; this includes planned new builds and planned retirements. In areas with a dense concentration of facilities, some facilities may be obscured.

6.1.2	Transmission
      Transmission is the term used to describe the movement of electricity over a network of high voltage lines, from electric generators to substations where power is stepped down for local distribution.  In the US and Canada, there are three separate interconnected networks of high voltage transmission lines, each operating at a common frequency.  Within each of these transmission networks, there are multiple areas where the operation of power plants is monitored and controlled to ensure that electricity generation and load are kept in balance.  In some areas, the operation of the transmission system is under the control of a single regional operator; in others, individual utilities coordinate the operations of their generation, transmission, and distribution systems to balance their common generation and load needs.
6.1.3	Distribution
      Distribution of electricity involves networks of lower voltage lines and substations that take the higher voltage power from the transmission system and step it down to lower voltage levels to match the needs of customers.  The transmission and distribution system is the classic example of a natural monopoly, in part because it is not practical to have more than one set of lines running from the electricity generating sources to substations or from substations to residences and business.
      Transmission has generally been developed by the larger vertically integrated utilities that typically operate generation and distribution networks.  Distribution is handled by a large number of utilities that often purchase and sell electricity, but do not generate it.  Transmission and distribution have been considered differently from generation in efforts to restructure the industry.  As discussed below, electricity restructuring has focused primarily on efforts to reorganize the industry to encourage competition in the generation segment of the industry, including ensuring open access of generation to the transmission and distribution services needed to deliver power to consumers.  In many state efforts, this has also included separating generation assets from transmission and distribution assets into distinct economic entities.  Transmission and distribution remain price-regulated throughout the country based on the cost of service.

6.2	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 possibility of lower electric rates, reduced costs of combustion turbine technology that opened the door for more companies to sell power, and complexity of monitoring utilities' cost of service and establishing cost-based rates for various customer classes (see Figure 6-1).
      The pace of restructuring in the electric power industry slowed significantly in response to market volatility and financial turmoil associated with bankruptcy filings of key energy companies in California.  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 6-2 below).  Another 18 other states that had seriously explored the possibility of deregulation in 2000 reported no legislative or regulatory activity in 2001 (DOE, EIA, 2003a) ("Not Active" in Figure 6-2 below).  Currently, there are 15 states where price deregulation of generation (restructuring) has occurred ("Active" in Figure 6-2 below).  Eight of these states are in the Transport Rule region.  The effort is more or less at a standstill; there have been no recent proposals to the Federal Energy Regulatory Commission (FERC) for actions aimed at wider restructuring, and no additional states have begun retail deregulation activity
      Figure 6-2.  Status of State Electricity Industry Restructuring Activities

Source: EIA http://www.eia.doe.gov/cneaf/electricity/page/restructuring/restructure_elect.html (September, 2010).

6.3	Pollution and EPA Regulation of Emissions
	The burning of fossil fuels, which generates about 70 percent of our electricity nationwide, results in air emissions of SO2 and NOX, important precursors in the formation of fine particles and ozone (NOX only).  The power sector is a major contributor of both these pollutants, and reductions of SO2 and NOX emissions are critical to EPA's efforts to bring about attainment with the fine particle and ozone NAAQS through programs like the Transport Rule.  In 2008, the power sector accounted for 66 percent of total nationwide SO2 emissions and 18 percent of total nationwide NOX emissions (see Figure 6-3).

Figure 6-3.  Emissions of SO2 and NOX from the Power Sector (2008)
Sulfur Dioxide
Power Sector (66%)
Nitrogen Oxides
Power Sector (18%)
Source: EPA http://www.epa.gov/ttn/chief/trends/
      Different types of fossil fuel-fired units vary widely in their air emissions levels for SO2 and NOX, particularly when uncontrolled.  For coal-fired units, NOX emissions rates can vary from under 0.05 lbs/mmBtu (for a unit with selective catalytic reduction (SCR) for NOX removal) to over 1 lb/mmBtu for an uncontrolled cyclone boiler.  NOX emissions from coal-fired power plants are formed during combustion and are a result of both nitrogen in coal and nitrogen in the air.  SO2 emissions rates can vary from under 0.1 lbs/mmBtu (for some units with flue gas desulfurization (FGD) for SO2 removal) to over 5 lbs/mmBtu for units burning higher sulfur coal without any pollution controls.  For an uncontrolled coal plant, SO2 emissions are directly related to the amount of sulfur in the coal.
      Oil- and gas-fired units also have a wide range of NOX emissions depending on both the plant type and the controls installed.  Gas-fired units with SCR can have emissions rates under 0.01 lbs/mmBtu, while completely uncontrolled units can have emissions rates in excess of 0.5 lbs/mmBtu.  Gas-fired units have very little SO2 emissions.  NOX emissions rates on oil-fired units can range from under 0.1 lbs/mmBtu (for units with new combustion controls) to over 0.6 lbs/mmBtu for units without combustion controls.  SO2 emissions for oil-fired units can range from under 0.1 lbs/mmBtu for units burning low sulfur distillate oil to over 2 lbs/mmBtu for units burning high sulfur residual oil.

6.4	Pollution Control Technologies
	There are three options for reducing SO2 emissions from coal-burning power plants.  Units may switch from higher to lower sulfur coal, blend higher sulfur coal with lower sulfur coal, or use post-combustion controls, such as FGD (commonly referred to as scrubbers) or Dry Sorbent Injection (DSI).  According to data submitted to EPA for compliance with the Title IV Acid Rain Program, the SO2 emissions rates for coal-fired units without controls varied from under 0.4 lbs/mmBtu to over 5 lbs/mmBtu depending on the type of coal combusted.  With controls, rates range from as low as 0.03 lbs/mmBtu to close to 1 lb/mmBtu.
      It is generally easier to switch to a coal within the same rank (e.g., bituminous or sub-bituminous) because these coals will have similar heat contents and other characteristics.  Switching completely to sub-bituminous coal (which typically has lower sulfur content) from bituminous coal is likely to require some modifications to the unit.  Limited blending of sub-bituminous coal with bituminous coal can often be done with fewer modifications.
      The two most commonly used scrubber types include wet scrubbers and spray dryers, also known as dry scrubbers.  Wet scrubbers can use a variety of sorbents to capture SO2, including limestone and magnesium-enhanced lime.  The choice of sorbent can affect the performance, size, and capital and operating costs of the scrubber.  New wet scrubbers typically achieve at least 96 percent SO2 removal.  Spray dryers use lime-based slurry and can achieve 92 percent removal.
      An alternative to wet and dry scrubber technology is dry sorbent injection (DSI), which injects an alkaline powdered material (post combustion) to react with SO2 and other acid gasses.  The reacted product is removed by particulate matter (PM) control device.  DSI technology is most efficient with a baghouse present downstream but can function with an electrostatic precipitator (ESP) downstream as well.  Under these circumstances, the ESP requires more reagent per molecule of acid gas removed as compared to a similar operation with a baghouse.   Finally, DSI may employ a multitude of sorbents (Trona, sodium carbonate, calcium carbonate  -  and their bicarbonate counterparts) for a more tailored approach to reduce emissions based on the source, cost, and unit and fuel characteristics.
      One method of reducing NOX emissions is through the use of combustion controls (such as low NOX burners and over-fire air).  Combustion controls adjust the coal combustion conditions to those where less formation of NOX occurs.  Post-combustion controls remove the NOX after it has been formed.  The most common post-combustion control is SCR.  In SCR systems ammonia (NH3) is injected, which combines with the NOX in the flue gas, to form nitrogen and water and uses a catalyst to enhance the reaction.  These systems can reduce NOX by 90 percent and achieve emissions rates of around 0.06 lbs/mmBtu.  Another post-combustion control is Selective Non-catalytic Reduction (SNCR).  In this technology NOX also is removed by injecting ammonia, but no catalyst is used.  SNCR systems can reduce NOX by up to 40 percent.
      Some of the same control options available to coal-fired units are also applicable to units fueled by oil or gas.  Combustion controls, SCR, and SNCR can also be applied to oil- and gas-fired boilers for NOX control.  Combustion controls and SCR are also routinely used for NOX control on gas turbines.
      For more detail on the cost and performance assumptions of pollution controls, see the documentation for the Integrated Planning Model (IPM), a dynamic linear programming model that EPA uses to examine air pollution control policies for SO2 and NOX throughout the contiguous United States for the entire power system.  Documentation for IPM can be found at www.epa.gov/airmarkets/epa-ipm.

6.5	Air Regulation of the Power Sector
	At the federal level, efforts to reduce emissions of SO2 have been occurring since 1970.  Policy makers have recognized the need to address these harmful emissions, and incremental steps have been taken to ensure that the country meets air quality standards.  The Transport Rule is the next step towards realizing attainment of the national standards for PM2.5 and ozone.
	Even before widespread regulation of SO2 and NOX for the power sector, total suspended particulate matter (TSP) was a related target of state and federal action.  Because larger particulates are visible as dark smoke from smokestacks, most states had regulations by 1970 limiting the opacity of emissions.  Requirements for taller smokestacks also mitigated local impacts of TSP.  Notably, such regulations effectively addressed large-diameter, filterable particulate matter rather than condensable particulate matter (such as PM2.5) associated with SO2 and NOX emissions, which are not visible at the smokestack and have impacts far from their sources.
      Federal regulation of SO2 and NOX emissions at power plants began with the 1970 Clean Air Act.  The Act required the Agency to develop New Source Performance Standards (NSPS) for a number of source categories including coal-fired power plants.  The first NSPS for power plants (subpart D) required new units to limit SO2 emissions either by using scrubbers or by using low sulfur coal.  NOX was required to be limited through the use of low NOX burners.  A new NSPS (subpart Da), promulgated in 1978, tightened the standards for SO2, requiring scrubbers on all new units.
      The 1990 Clean Air Act Amendments (CAAA) placed a number of new requirements on power plants.  The Acid Rain Program, established under Title IV of the 1990 CAAA, requires major reductions of SO2 and NOX emissions.  The SO2 program sets a permanent cap on the total amount of SO2 that can be emitted by electric power plants in the contiguous United States at about one-half of the amount of SO2 these sources emitted in 1980.  Using a market-based cap and trade mechanism allows flexibility for individual combustion units to select their own methods of compliance with the SO2 reduction requirements.  The program uses a more traditional approach to NOX emissions limitations for certain coal-fired electric utility boilers, with the objective of achieving a 2 million ton reduction from projected NOX emission levels that would have been emitted in 2000 without implementation of Title IV.
      The Acid Rain Program comprises two phases for SO2 and NOX.  Phase I applied primarily to the largest coal-fired electric generating sources from 1995 through 1999 for SO2 and from 1996 through 1999 for NOX.  Phase II for both pollutants began in 2000.  For SO2, it applies to thousands of combustion units generating electricity nationwide; for NOX it generally applies to affected units that burned coal during 1990 through 1995.  The Acid Rain Program has led to the installation of a number of scrubbers on existing coal-fired units as well as significant fuel switching to lower sulfur coals.  Under the NOX provisions of Title IV, most existing coal-fired units installed low NOX burners.
      The CAAA also placed much greater emphasis on control of NOX to reduce ozone nonattainment.  This led to the formation of several regional NOX trading programs as well as intrastate NOX trading programs in states such as Texas.  The northeastern states of the Ozone Transport Commission (OTC) required existing sources to meet Reasonably Available Control Technology (RACT) limits on NOX in 1995 and in 1999 began an ozone-season cap and trade program to achieve deeper reductions.  In 1998, EPA promulgated regulations (the NOX SIP Call) that required 21 states in the eastern United States and the District of Columbia to reduce NOX emissions that contributed to nonattainment in downwind states using the cap and trade approach.  This program began in May of 2003 and has resulted in the installation of significant amounts of selective catalytic reduction.
      The Clean Air Interstate Rule (CAIR) built on EPA's efforts in the NOX SIP call to address specifically interstate pollution transport for ozone, and was EPA's first attempt to address interstate pollution transport for PM2.5.  It required significant reductions in emissions of SO2 and NOX in 28 states and the District of Columbia (see Figure 6-4 below).  EGUs were found to be a major source of the SO2 and NOX emissions which contributed to fine particle concentrations and ozone problems downwind.  Although the D.C. Circuit remanded the rule to EPA in 2008, it did so without vacatur, allowing the rule to remain in effect while EPA addresses the remand.  Thus, CAIR is continuing to help states address ozone and PM2.5 nonattainment and improve visibility by reducing transported precursors of SO2 and NOX through the implementation of three separate cap and trade compliance programs for annual NOX, ozone season NOX, and annual SO2 emissions from power plants.
Figure 6-4.  States Covered under the Clean Air Interstate Rule

      Perhaps in anticipation of complying with CAIR, especially the more stringent second phase that was set to begin in 2015, several sources have recently been installing or planning to install advanced controls for SO2 and NOX to begin operating in the 2010 to 2015 timeframe.  Many EPA New Source Review (NSR) settlements also require controls in those years, as do state rules in Georgia, Illinois, and Maryland.  States like North Carolina, New York, Connecticut, Massachusetts, and Delaware have also moved to control these emissions to address nonattainment.  Thus both federal and state efforts are continuing to bring about sizeable reductions in SO2 and NOX from the power sector.  Section 6-1 below discusses how these recent activities are reflected in the Transport Rule base case.  Details of the NSR settlements and state controls can be found in the IPM documentation referenced earlier.
6.6	Revenues, Expenses, and Prices
Due to lower retail electricity sales, total utility operating revenues declined in 2009 to $276 billion from a peak of almost $300 billion in 2008.  However, operating expenses were appreciably lower and as a result, net income actually rose modestly compared to 2008 (see Table 6-5).  Recent economic events have put downward pressure on electricity demand, thus dampening electricity prices (utility revenues), but have also reduced the price and cost of fossil fuels and other expenses.  Electricity sales and revenues associated with the generation, transmission, and distribution of electricity are expected to rebound and increase modestly by 2015, where they are projected to be roughly $360 billion (see Table 6-6).
Table 6-5.  Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities for 2009 ($millions)

                                     2008
                                     2009
Utility Operating Revenues
                                                                        298,962
                                                                        276,124
Electric Utility
                                                                        266,124
                                                                        249,303
Other Utility
                                                                         32,838
                                                                         26,822
Utility Operating Expenses
                                                                        267,263
                                                                        244,243
Electric Utility
                                                                        236,572
                                                                        219,544
Operation
                                                                        175,887
                                                                        154,925
Production
                                                                        140,974
                                                                        118,816
Cost of Fuel
                                                                         47,337
                                                                         40,242
Purchased Power
                                                                         84,724
                                                                         67,630
Other
                                                                          8,937
                                                                         10,970
Transmission
                                                                          6,950
                                                                          6,742
Distribution
                                                                          3,997
                                                                          3,947
Customer Accounts
                                                                          5,286
                                                                          5,203
Customer Service
                                                                          3,567
                                                                          3,857
Sales
                                                                            225
                                                                            178
Administrative and General
                                                                         14,718
                                                                         15,991
Maintenance
                                                                         14,192
                                                                         14,092
Depreciation
                                                                         19,049
                                                                         20,095
Taxes and Other
                                                                         26,202
                                                                         29,081
Other Utility
                                                                         30,692
                                                                         24,698
Net Utility Operating Income
                                                                         31,699
                                                                         31,881

                       Source:  EIA Electric Power Annual 2009, Table 8.1
                       Note: This data does not include information for public utilities.

Table 6-6.  Projected Revenues by Service Category in 2015 for Public Power and Investor-Owned Utilities (billions)

  Generation
                                                                           $195
  Transmission
                                                                            $36
  Distribution
                                                                           $129

                                                                           $360
Notes: Data is from EIA's AEO 2011, and is derived by taking either total electricity use (for generation) or sales (transmission and distribution) and multiplying by forecasted prices by service category from Table 8 (Electricity Supply, Disposition, Prices, and Emissions).
      Based on EIA's Annual Energy Outlook 2011, Table 6-6 shows that in the base case, the power sector is expected to derive revenues of $360 billion in 2015.  Table 6-5 shows that investor-owned utilities (IOUs) earned income of about 11.5% compared to total revenues in 2009.  Assuming the same income ratio from IOUs (with no income kept by public power), and using the same proportion of power sales from public power as observed in 2009, EPA projects that the power sector will expend over $320 billion in 2015 alone to generate, transmit, and distribute electricity to end-use consumers.
      Over the past 50 years, real retail electricity prices have ranged from around 7 cents per kWh in the early 1970s, to around 11 cents, reached in the early 1980s.  Generally, retail electricity prices do not change rapidly and do not display the variability of other energy or commodity prices.  Retail rate regulation has largely insulated consumers from the rising and falling wholesale electricity price signals whose variation on an hourly, daily, and seasonal basis is critical for driving lowest-cost matching of supply and demand.  In fact, the real price of electricity today is lower than it was in the early 1960s and 1980s (see Figure 6-5).

Figure 6-5.  National Average Retail Electricity Price (1960  -  2009)

		   Source: EIA's Annual Energy Review 2009

	On a state-by-state basis, retail electricity prices vary considerably.  The Northeast and California have average retail prices that can be as much as double those of other states. (see Figure 6-6)

Figure 6-6  Average Retail Electricity Price by State (cents/kWh), 2009

6.6.1	Natural Gas Prices
	The natural gas market in the United States has historically experienced significant price volatility from year to year, between seasons within a year, and can undergo major price swings during short-lived weather events (such as cold snaps leading to short-run spikes in heating demand).  Over the last decade, gas prices (both Henry Hub prices and delivered prices to the power sector) have ranged from $3 per mmBtu to as high as $9 on an annual average basis (see Figure 6-7).  During that time, the daily price of natural gas reached as high as $15/mmBtu.  Recent forecasts of natural gas have also experienced considerable revision as new sources of gas have been discovered and come to market.

Figure 6-7.  Natural Gas Spot Price, Annual Average (Henry Hub)

Source: EIA

6.7	Electricity Demand and Demand Response
	Electricity performs a vital and high-value function in the economy.  Historically, growth in electricity consumption has been closely aligned with economic growth.  Overall, the U.S. economy has become more efficient over time, producing more output (GDP) per unit of energy input, with per capita energy use fairly constant over the past 30 years.  The growth rate of electricity demand has also been in overall decline for the past sixty years (see Figure 6-8), with several key drivers that are worth noting.  First, there has been a significant structural shift in the U.S. economy towards less energy-intensive sectors, like services.  Second, companies have strong financial incentives to reduce energy expenditures.  Third, companies are responding to the marketplace and continually develop and bring to market new technologies that reduce energy consumption.  Fourth, complementary policies and energy efficiency standards at the state and Federal level have helped address market failures.  These broader changes have altered the outlook for future electricity growth (see Figure 6-8).

Figure 6-8.  Electricity Growth Rate (3 Year Rolling Average) and Projections from the Annual Energy Outlook 2011

	       Source: EIA Annual Energy Review 2009 and Annual Energy Outlook 2011
	Energy efficiency initiatives have become more common, and investments in energy efficiency are projected to continue to increase for the next 5 to 10 years, driven in part by the growing number of states that have adopted energy efficiency resource standards.  These investments, and other energy efficiency policies at both the state and federal level, create incentives to reduce energy consumption and peak load.  According to EIA, demand-side management provided actual peak load reductions of 31.7 GW in 2009.  For context, the current coal fleet is roughly 320 GW of capacity.
	Demand for electricity, especially in the short run, is not very sensitive to changes in prices and is considered relatively price inelastic, although some demand reduction does occur in response to price.  With that in mind, EPA modeling does not typically incorporate a "demand response" in its electric generation modeling (Chapter 8) to the increases in electricity prices typically projected for EPA rulemakings.  Electricity demand is considered to be constant in EPA modeling applications and the reduction in production costs that would result from lower demand is not considered in the primary analytical scenario that is modeled.  This leads to some overstatement in the private compliance costs that EPA estimates.  Notably, the "compliance costs" are the changes in the electric power generation costs in the base case and pollution control options that are evaluated in Chapter 7.  In simple terms, it is the resource costs of what the power industry will directly expend to comply with EPA's requirements.

6.8	Reference
EIA Electric Power Annual 2009.  DOE/EIA-0348 (2009).  Available at: http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.htm

                                   CHAPTER 7
                      COST, ECONOMIC, AND ENERGY IMPACTS

      This chapter reports the cost, economic, and energy impact analysis performed for the Transport Rule.  EPA used the Integrated Planning Model (IPM), developed by ICF Consulting, to conduct its analysis.  IPM is a dynamic linear programming model that can be used to examine air pollution control policies for SO2 and NOx (as well as other air pollutants) throughout the contiguous United States for the entire power system.  Documentation for IPM can be found at http://www.epa.gov/airmarkets/progsregs/epa-ipm, and updates specific to Transport Rule modeling are available in the document titled: "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule," available on the website and in the docket.
7.1	Background
      Over the last decade, EPA has on several occasions used IPM to consider control options for reducing power-sector SO2 and NOx for regional transport.  The best known example of one of these occasions is the Clean Air Interstate Rule (CAIR), the regulation that the current rule will replace.  , The example of CAIR along with the analysis of the final Transport Rule below provide context and suggest alternative approaches to the Transport Rule (see Keohane 2009, 34 - 35 and Wagner 2009, 59).
      Many EPA analyses with IPM have focused on legislative changes with national programs, such as EPA's IPM analyses of the Clean Air Planning Act (S.843 in 108th Congress), the Clean Power Act (S.150 in 109th Congress), the Clear Skies Act of 2005 (S.131 in 109th Congress), the Clear Skies Act of 2003 (S.485 in 108th Congress), and the Clear Skies Manager's Mark (of S.131).  These analyses are available at EPA's website: (www.epa.gov/airmarkets/progsregs/cair/multi.html).  EPA's IPM analysis for CAIR is another example of how the model has been used in regulatory analysis of SO2 and NOX control strategies, in this case dealing with a regulatory approach focusing on the eastern US: (www.epa.gov/airmarkets/progsregs/epa-ipm/cair/index.html).  EPA also analyzed several multi-pollutant reduction scenarios in July 2009 at the request of Senator Tom Carper to illustrate the costs and benefits of multiple levels of SO2 and NOX control in the power sector.
      In addition, EPA conducted extensive state-by-state analysis of control levels and the associated emissions projections related to upwind pollution that crosses state borders and impacts a downwind state's air quality monitors for the Transport Rule.  More details on this analysis can be found in the Significant Contribution and State Emissions Budgets TSD.
      As discussed in section 6.5, this rule comes during a period when many new SO2 and NOx controls are being installed.  Many are needed for compliance with NSR settlements and state rules, while others may have been planned as a result of CAIR.  Because CAIR remains in effect until it is replaced, emission reductions continue in the eastern US.
      As discussed in section 2.4, the base case in this RIA assumes that CAIR is not in effect, but does take into account emissions reductions associated with the implementation of all federal rules, state rules and statutes, and other binding, enforceable commitments finalized by December 1, 2010, that are applicable the power industry and which govern the installation and operation of SO2 and NOx emissions controls in the timeframe covered in the analysis.
	To address air quality problems, improve public health and the environment, and to respond to the Court decision in North Carolina v. EPA, the Agency is finalizing the Transport Rule.  The Transport Rule requires annual SO2 and NOx reductions in 23 states, and also requires ozone season NOx reductions in 20 States.  Many of the Transport Rule states are affected by both the annual SO2 and NOx reduction requirements and the ozone season NOx requirements.
      The rule affects roughly 3,700 fossil-fuel-fired units with a nameplate capacity greater than 25 MW located at nearly 1,100 facilities.  These sources accounted for roughly 82 percent of nationwide SO2 emissions and 67 percent of nationwide NOx emissions in 2010 (see Table 7-1).

Table 7-1.  Annual Emissions of SO2 and NOx in 2010 and Percentage of Emissions in the Transport Rule Affected Region (tons)

                                      SO2
                                      NOX
Transport Rule
Annual NOX and SO2 States
                                   4,251,996
                                   1,424,228
Nationwide
(Contiguous 48 States)
                                   5,165,954
                                   2,136,612
Emissions of Transport Rule States as Percentage of Nationwide Emissions
                                      82%
                                      67%

Source: EPA emissions data from all reporting units.
Note: Transport Rule annual NOX and SO2 states include Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin.

      For SO2 and annual NOx, EPA modeled control requirements beginning in 2012 for the 23 eastern states shown in blue and green in Figure 7-1 below.  In 16 of those states (shown in green), more stringent SO2 requirements begin in 2014.  For ozone-season NOx, separate ozone-season requirements were applied to the 26 states shown in green and yellow in Figure 7-1.  Many of the Transport Rule states are affected by both the annual SO2 and NOx reduction requirements and the ozone-season (May - September) NOx requirements.  Table 7-2 show the emission budgets allotted to each state.  For further discussion about the scope and requirements of the Transport Rule, see the Transport Rule preamble or Chapter 2 of this RIA.
      As previously stated, the emissions, cost, air quality, and benefits analyses done for the Transport Rule are from a modeling scenario that requires annual SO2 and NOx reductions in 23 states and ozone season NOx requirements in 26 states (See Figure 7-1).  This modeling differs from the final Transport Rule because it includes ozone season NOX requirements for six states (Iowa, Kansas, Michigan, Missouri, Oklahoma, and Wisconsin) that the final Transport Rule does not cover. (As discussed in the preamble to the final rule, EPA is issuing a supplemental proposal to request comment on the inclusion of these six states).  Results presented in this chapter reflect inclusion of these six states in the Transport Rule.
Figure 7-1.  Transport Rule Covered States

Table 7-2.  Transport Rule Annual NOx and SO2 and NOx Ozone Season State Emission Budgets (tons)

                                  SO2
Annual
                                  NOX
Annual
                               NOX
Ozone Season

                                 2012 and 2013
                                2014 and Later
                                 2012 and 2013
                                2014 and Later
                                 2012 and 2013
                                2014 and Later
Alabama
           216,033
              213,258
                   72,691
                71,962
                   31,746
                  31,499
Arkansas
---
---
---
---
                   15,037
                  15,037
Florida
---
---
---
---
                   27,825
                  27,825
Georgia
           158,527
                95,231
                   62,010
                40,540
                   27,944
                  18,279
Illinois
           234,889
              124,123
                   47,872
                47,872
                   21,208
                  21,208
Indiana
           285,424
              161,111
                 109,726
              108,424
                   46,876
                  46,175
Iowa
           107,085
                75,184
                   38,335
                37,498
                   16,532*
                  16,207*
Kansas
             41,528
                41,528
                   30,714
                25,560
                   13,536*
                  10,998*
Kentucky
                                                                     232,662ª
              106,284
                   85,086
                77,238
                   36,167
                  32,674
Louisiana
---
---
---
---
                   13,432
                  13,432
Maryland
             30,120
                28,203
                   16,633
                16,574
                     7,179
                    7,179
Michigan
           229,303ª
              143,995
                   60,193
                57,812
                   25,752*
                  24,727*
Minnesota
             41,981
                41,981
                   29,572
                29,572
---
---
Mississippi
---
---
---
---
                   10,160
                  10,160
Missouri
           207,466
              165,941
                   52,374
                48,717
                   22,762*
                  21,073*
Nebraska
             65,052
                65,052
                   26,440
                26,440
---
---
New Jersey
               5,574
                  5,574
                     7,266
                  7,266
                     3,382
                    3,382
New York
             27,325ª
                18,585ª
                   17,543
                17,543
                     8,331
                    8,331
North Carolina
           136,881
                57,620
                   50,587
                41,553
                   22,168
                  18,455
Ohio
           310,230
              137,077
                   92,703
                87,493
                   40,063
                  37,792
Oklahoma
---
---
---
---
                   21,835*
                  21,835*
Pennsylvania
           278,651
              112,021
                 119,986
              119,194
                   52,201
                  51,912
South Carolina
             88,620
                88,620
                   32,498
                32,498
                   13,909
                  13,909
Tennessee
           148,150
                58,833
                   35,703
                19,337
                   14,908
                    8,016
Texas
           243,954
              243,954
                 133,595
              133,595
                   63,043
                  63,043
Virginia
             70,820
                35,057
                   33,242
                33,242
                   14,452
                  14,452
West Virginia
           146,174
                75,668
                   59,472
                54,582
                   25,283
                  23,291
Wisconsin*
             79,480
                40,126
                   31,628
                30,398
                   13,704
                  13,216
Total
        3,301,008
           2,128,264
                 609,435
                574,107
              1,245,869
           1,164,910

*Note: as discussed in the preamble to the final rule, EPA is issuing a supplemental proposal to request comment on inclusion of these six states in the Ozone Season program.
ª These budgets reflect small technical revisions which were made after the analyses presented in this RIA were completed.  EPA conducted a sensitivity analysis including these revised budgets to confirm that the analytic findings presented in this RIA are still valid for the expected impacts of the program with the budgets and variability limits as finalized.  Results from that analysis are presented in Appendix [X] of this RIA.

      Electricity demand is anticipated to grow by roughly 1 percent a year, and total electricity demand is projected to be 4,106 billion kWh by 2014.  Table 7-3 shows current electricity generation alongside EPA's base case projections using EPA's IPM modeling. This rule relies on EIA's Annual Energy Outlook for 2010's electric demand forecast for the US and employs a set of EPA assumptions regarding fuel supplies and the performance and cost of electric generation technologies as well as pollution controls.  The base case assumption that CAIR is not in effect does have some modest influence on the fossil generation mix in this forecast, because CAIR had increased the costs of coal-fired generation relatively more than it had increased the costs to generation units that burned oil or natural gas.
Table 7-3.  2009 Electricity Net Generation and EPA Base Case Projections for 2012, 2014, 2020 and 2030 for the Contiguous 48 States (Billion kWh)

                                  Historical
                                   Base Case

                                     2009
                                     2012
                                     2014
                                     2020
                                     2030
Coal
                                     1,754
                                     1,958
                                     2,017
                                     2,037
                                     2,071
Oil
                                      29
                                     0.09
                                     0.10
                                     0.14
                                     0.19
Natural Gas
                                      917
                                      721
                                      686
                                      823
                                     1,155
Nuclear
                                      799
                                      812
                                      822
                                      832
                                      811
Hydroelectric
                                      272
                                      281
                                      287
                                      287
                                      286
Non-hydro Renewables
                                      143
                                      233
                                      250
                                      288
                                      328
Other
                                       0
                                      35
                                      45
                                      44
                                      53
Total
                                     3,914
                                     4,041
                                     4,107
                                     4,311
                                     4,704

Source: 2009 data from EIA Electric Power Annual 2009, Table 1.1 (adjusted to represent the Contiguous 48 States for consistency with projections, which are from the Integrated Planning Model run by EPA, 2011).
      As noted above, IPM has been used for evaluating the economic and emission impacts of environmental policies for over a decade.  The economic modeling presented in this chapter has been developed for specific analyses of the power sector.  Thus, the model has been designed to reflect the industry as accurately as possible.  As a result, EPA has used discount rates in IPM that are appropriate for the various types of investments and other costs that the power sector incurs (for example, the primary real discount rate is 5.5 % for pollution control retrofits).  The discount rates used in IPM differ from discount rates used in other RIA analyses done for the Transport Rule, particularly the discount rates used in the benefits and macroeconomic analyses that are assumed to be social discount rates. (See Chapters 5 and 8 where social discount rates of 3% and 7% are used.)  EPA uses the best available information from utilities, financial institutions, debt rating agencies, and government statistics as the basis for the discount rates used for power sector modeling in IPM.  These discount rates have undergone review by the power sector and the Energy Information Administration.
      More detail on IPM can be found in the model documentation, which provides additional information on the assumptions discussed here as well as all other assumptions and inputs to the model (http://www.epa.gov/airmarkets/progsregs/epa-ipm).  Updates specific to Transport Rule modeling are also in the document titled: "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule."

7.2	Projected SO2 and NOx Emissions and Reductions
      The Transport Rule achieves substantial emission reductions.  EPA projects annual SO2 emission reductions of 62 percent and annual NOx emission reductions of 11 percent in the covered region by 2014 relative to the base case.  Additionally, EPA projects ozone-season NOx reductions of 11 percent in the Transport Rule region (see Table 7-4). There is also a small decrease in CO2 emissions as a result of the Transport Rule.
      In Figure 7-2 below, the results of EPA modeling of the Transport Rule show that substantial SO2 emission reductions occur in the Midwest and Mid-Atlantic regions of the country.  Because banking of allowances is allowed to encourage early reductions, 2012 SO2 reductions are greater overall than state budgets alone would require in that year.  For many coal-fired electric generation units throughout the region it is economically advantageous to make extra emissions reductions in 2012 through fuel switching to have allowances to later use or sell in 2014 and beyond, when the Transport Rule becomes more stringent and when electric generators will also need to meet higher electric demand.  Because of the banking provisions, the relative economics of making pollution reductions below the state assurance levels in 2012 versus making emissions reductions later favor doing more in 2012.  Annual NOx emissions reductions occur across the Transport Rule region (see Figure 7-3), and with the Transport Rule, ozone-season NOx emission reductions are lower than they would have been with the NOx SIP Call (base case) (see Figure 7-4).

Table 7-4.  Projected Emissions of SO2, NOX, and CO2 with the Base Case (No Further Controls) and with Transport Rule (Million Short Tons)

                                     2012
                                     2014

                                     Base
                                      TR
                                    Change
                                   % Change
                                     Base
                                      TR
                                    Change
                                   % Change
                                 SO2 (Annual)
Contiguous 48 States
                                      7.9
                                      3.9
                                     -3.9
                                     -50%
                                      7.2
                                      3.4
                                     -3.8
                                     -53%

TR States
                                      7.0
                                      3.0
                                     -4.0
                                     -57%
                                      6.2
                                      2.4
                                     -3.9
                                     -62%
                                 NOX (Annual)
Contiguous 48 States
                                      2.1
                                      2.0
                                     -0.2
                                      -7%
                                      2.1
                                      1.9
                                     -0.2
                                      -9%

TR States
                                      1.4
                                      1.3
                                     -0.1
                                      -9%
                                      1.4
                                      1.2
                                     -0.2
                                     -11%
                                 NOX (Summer)
Contiguous 48 States
                                      0.9
                                      0.9
                                     -0.1
                                      -7%
                                      0.9
                                      0.8
                                     -0.1
                                      -9%

TR States
                                      0.7
                                      0.6
                                     -0.1
                                      -9%
                                      0.7
                                      0.6
                                     -0.1
                                     -11%
                                  oo CO2 (Annual)
     oo Contiguous 48 States
                                      oo 2,444
                                      oo 2,431
                                       oo -13
                                       oo -1%
                                      oo 2,482
                                      oo 2,454
                                       oo -28
                                       oo -1%

TR States
                                     1,769
                                     1,749
                                      -20
                                      -1%
                                     1,799
                                     1,765
                                      -44
                                      -2%

Note:	Numbers may not add due to rounding.  The emissions data presented here are EPA modeling results and the Transport Rule region includes states modeled for the annual SO2 and NOx requirements.  "Summer" is from May 1 - September 30, which is the ozone season.  Base case includes Title IV Acid Rain Program, NOx SIP Call, and state rules through December 1, 2010.
Source:	Integrated Planning Model run by EPA, 2011.

Figure 7-2.  SO2 Emissions from the Power Sector in 2012 and 2014 with and without the Transport Rule

Source:	EPA, IPM, 2011.

Figure 7-3.  Annual NOx Emissions from the Power Sector in 2012 and 2014 with and without the Transport Rule
Source:	EPA, IPM, 2011.

Figure 7-4.  Ozone-season NOx Emissions from the Power Sector in 2012 and 2014 with and without Transport Rule

Source:	EPA, IPM, 2011.

	7.3	Overview of Costs and Other Impacts
	As shown above in Figure 7-1, the Transport Rule directly affects 23 states in controlling pollution related to fine particles.  For ozone, it also affects a distinct but overlapping group of 20 states.  The states in one or both of these regions constitute most of the fossil-fuel-fired generation and capacity in the contiguous US, especially coal-fired (see Tables 7-5 and 7-6 below).

Table 7-5.  2010 Fossil-fuel Generation Nationwide and in the Transport Region (Thousand Megawatthours)

                                 Contiguous US
                       Transport Rule Fine Particle Area
                           Transport Rule Ozone Area
Coal-fired
                                   1,829,176
                                   1,405,021
                                   1,510,557
Oil-fired
                                    13,680
                                     5,955
                                    12,080
Natural Gas-fired
                                    894,598
                                    409,534
                                    633,636
Total
                                   3,954,846
                                   2,598,207
                                   2,989,910

Source: EIA Electric Power Monthly with data for December 2010, Tables 1.6B, 1.7.B, 1.8.B, 1.10.B.

Table 7-6.  Total Fossil-fuel Capacity Nationwide and in the Transport Region

                                 Contiguous US
                       Transport Rule Fine Particle Area
                           Transport Rule Ozone Area
Pulverized Coal
                                      316
                                      247
                                      266
Combined Cycle
                                      199
                                      97
                                      142
Other Oil/Gas
                                      247
                                      155
                                      196
Total
                                      998
                                      630
                                      743

Source: EPA's NEEDS v4.10.

	While most impacts of the Transport Rule affect the covered states themselves, national impacts are important.  Because the electric grid is connected irrespective of state boundaries, effects on electrical generation in one state have spillover effects in other states.  Likewise, because the Transport Rule states have the vast majority of coal-fired generation, changes in their coal consumption and demand affect coal prices nationwide.  In some cases, such as retail electricity prices and the operation of pollution controls, nationwide information would not be as relevant as regional totals.  But for most of the following sections, nationwide projections provide a more complete picture of the Transport Rule's impacts.
7.4	Projected Compliance Costs
      The power industry's "compliance costs" are the changes in electric power generation costs in the base case and alternative pollution control approaches that are examined in this chapter.  In simple terms, these costs are the resource costs of what the power industry will directly expend to comply with EPA's requirements.  This is not the "social cost" of the control approaches, which is separately explained and estimated in Chapter 8.
      EPA projects that the annual incremental compliance costs of the Transport Rule are $1.4 billion in 2012 and $0.8 billion in 2014 (see Table 7-7 below).  Another measure of this impact is the change in electricity prices (discussed in section 7.10).  Costs generally are higher in 2012 than in 2014 because of reduced compliance flexibility in 2012, which is too soon for sources to retrofit new FGD and SCR that were not already planned.

Table 7-7.  Annualized Compliance Cost of the Transport Rule

                                                                           2012
                                                                           2014
                                                                           2020
Annualized Compliance Cost
(billions of 2007$)
                                                                           $1.4
                                                                           $0.8
                                                                           $0.6

Note: Numbers rounded to the nearest hundred million for annualized cost.
Source: Integrated Planning Model run by EPA, 2011.

      For context, the projected annualized compliance costs are a small fraction of the $320 billion in expenditures EPA projects that the power sector will make in 2015 alone to generate, transmit, and distribute electricity to end-use consumers.  For more information, see Chapter 6.

7.5	Projected Approaches to Emissions Reductions
      Fossil-fuel-fired electric generating units in the Transport Region are projected to achieve NOx and SO2 emissions reductions through a combination of compliance options. These actions include sustained operation of existing controls originally built for CAIR, additional pollution control installations at coal-fired generators, coal switching (including blending of coals), and increased dispatch of more efficient units and lower-emitting generation technologies (e.g., some reduction of coal-fired generation with an increase of generation from natural gas).  In addition, there will be some affected sources that find it more economic to retire rather than invest in new pollution control equipment.  These facilities are generally amongst the oldest, least efficient power plants and typically run infrequently.
      In 2012, a small shift from coal- and oil-fired generation to greater use of natural gas lowers emissions a small amount (see Table 7-11).  NOx emissions reductions largely stem from year-round operation of selective catalytic reduction (SCR) controls that would otherwise operate only during the ozone season (see Table 7-10).  Additionally, a modest amount of NOx reduction stems from new low- NOx burners installations on older coal-fired units in states that were not in the original CAIR program but are covered in the ozone program of this rule.  The Transport Rule's 2012 SO2 emissions reductions largely result from sustained operation of all existing FGDs (scrubbers) in states controlled for PM, including those scrubbers built originally for CAIR and which may not have reason to operatein the absence of the Transport Rule.  Other 2012 SO2 reductions are achieved by units choosing to burn lower-sulfur coals as the least-cost compliance approach.  In 2014, the Transport Rule drives the sector to install 5.9 GW of new FGD and 3 GW of new dry sorbent injection (DSI), which allow for significant additional SO2 reductions in the Group 1 states.
      Table 7-8 below provides a profile of sulfur contents in alternative coal supplies that offer substantial SO2 reduction opportunities by increased blending or fuel-switching to cleaner grades.  The table shows the degree to which uncontrolled coal-fired generation switches from relatively dirtier coals to relatively cleaner coals in response to imposition of the Transport Rule.

Table 7-8.  Percent of Generation without SO2 Controls by Coal Sulfur Content, 2014

                          Very Low
(<0.8 lb/mmBtu)
                           Low
(0.81-1.2 lbs/mmBtu)
                       Low-Medium
(1.21-1.66 lbs/mmBtu)
                       High-Medium
(1.67-3.34 lb/mmBtu)
                           High
(>3.35 lb/mmBtu)
Base Case
                                      27%
                                      37%
                                      8%
                                      15%
                                      13%
Transport Rule
                                      59%
                                      28%
                                      7%
                                      3%
                                      2%
Source: Integrated Planning Model run by EPA, 2011.

      Table 7-9 shows total coal use among both controlled (i.e., operating either FGD or DSI) and uncontrolled EGUs in the states subject to the SO2 program.  The Transport Rule is associated with only a slight reduction (3% in 2014) in total coal use compared to the base case.  More importantly, the table reinforces that the rule drives increased overall use of cleaner bituminous and subbituminous coals, especially very low sulfur subbituminous.  This trend appears even when, as in this table, coal use at controlled units and very small units are included.

Table 7-9.  Coal Use by Sulfur Category in the PM2.5 Transport Region for the Base Case and Transport Rule* (million short tons)

                                    Lignite
                                 Subbituminous
                                  Bituminous
                                     Total

                                  High sulfur
                                  Low sulfur
                                Very low sulfur
                                  High sulfur
                              High-medium sulfur
                               Low-medium sulfur
                                  Low sulfur

                                     2012
Base
                                      30
                                      13
                                      145
                                      156
                                      91
                                      211
                                      83
                                       3
                                      732

TR
                                      25
                                       2
                                      77
                                      255
                                      83
                                      195
                                      74
                                      12
                                      723
                                     2014
Base
                                      37
                                      13
                                      145
                                      154
                                      102
                                      216
                                      71
                                       9
                                      747

TR
                                      32
                                       2
                                      108
                                      202
                                      88
                                      202
                                      73
                                      18
                                      724

*These coal usage results are for the 23 states covered by the rule in the trading program to reduce SO2 emissions.  Source: Integrated Planning Model run by EPA, 2011.

      EPA does not project additional SO2 control retrofits in 2012.  For SO2, EPA believes that to meet the 2012/2013 state assurance levels, compliance strategies would at most involve: operation of existing controls year-round, operation of controls that are scheduled to become operational by 2012, switching to a lower sulfur coal, and/or a general optimization of dispatch.  EPA projects incremental FGD installations of about 5.9 GW by 2014 (see Table 7-10).  These FGD retrofits are primarily wet scrubbers.  Additionally, approximately 3 GW of DSI is projected to be installed by 2014.  EPA believes that the January 1, 2014 starting date is as expeditious as practicable for sources to install such controls, and that retrofits of this limited extent can be realized in the 30 month interim between signature and the start of 2014.  For further discussion, see discussion in section VII.C.2 of the preamble.

Table 7-10.  Newly-Constructed Advanced SO2 Control Retrofits on Coal-fired Generation by Technology Built with the Base Case and with the Transport Rule (GW) in 2014

                                   Base Case
                                Transport Rule
                             Incremental Retrofits
Wet FGD
                                      4.6
                                     10.3
                                      5.7
Dry FGD
                                      3.6
                                      3.8
                                      0.2
DSI
                                      6.8
                                      9.8
                                      3.0
Note: FGD (Flue Gas Desulphurization) and DSI (Dry Sorbent Injection) are advanced SO2 controls.  Source: Integrated Planning Model run by EPA, 2011.

      In 2014, the Transport Rule is also projected to result in the operation of an additional 25 GW of flue gas desulfurization (scrubbers) for SO2 control and the year-round operation of an additional 5 GW of selective catalytic reduction technology (SCR) for NOx control on existing coal-fired generation capacity (see "Existing Controls Induced to Operate" in Table 7-11).    These controls were largely built for compliance with CAIR and are thus assumed not to operate in the base case.

Table 7-11.  Coal-fired Capacity Operating Advanced Pollution Controls with the Transport Rule, 2014 (GW)

                     Existing Controls Induced to Operate
                             Newly-Built Controls
                          Total Operational Controls
FGD
                                      25
                                       6
                                      209
DSI
                                       0
                                       3
                                      10
SCR
                                       5
                                       0
                                      146
Note: FGD (Flue Gas Desulphurization) and DSI (Dry Sorbent Injection) are advanced SO2 controls.  SCR (Selective Catalytic Reduction) is an advanced NOX control.  Source: Integrated Planning Model run by EPA, 2011.

      Projected operation of advanced pollution controls accounts for the vast majority of the NOx reductions, while for SO2 the reductions from the FGD and DSI controls are also supplemented by the continued and expanded use of relatively cleaner coals at uncontrolled units.

7.6 Projected Allowance Prices
	Table 7-12 shows the projected allowance prices for the four trading programs under the Transport Rule in 2012 and 2014. These are the marginal emission reduction costs (i.e., the cost of reducing the last ton of a pollutant subject to the Transport Rule budgets) that EPA projected using the Integrated Planning Model (IPM) to analyze the final rule's remedy, in those states where the variability limits do not bind (in states where the variability limits bind, the marginal cost of emission reductions is higher than the allowance price). Under the trading programs, the marginal emission reduction costs inform the market-clearing price to emit that balances the supply of and demand for allowances under the Transport Rule programs.
	The projected allowance prices differ from the cost-effective thresholds that were the original basis of the state budgets because they reflect the ability of the electricity sector to use the trading program flexibilities to achieve the aggregate required cost-effective emission reductions at minimized marginal costs. Most notably, banking allows entities to make emission reductions beyond what is needed in early years (accelerating environmental improvements) and smooth the trajectory of emission reductions in later years to minimize cost.
	EPA believes that these projected marginal costs under the Transport Rule programs can inform allowance price discovery as program participants seek cost-effective reductions at individual units and in the compliance marketplace.

Table 7-12. Projected allowance prices for the four Transport Rule programs in 2012 and 2014 (2007$)

                              Emission Allowance
                                Prices ($/Ton)

                                     2012
                                     2014
Annual SO2 Group 1 Trading Program
                                     1,000
                                     1,100
Annual SO2 Group 2 Trading Program
                                      600
                                      700
Annual NOx Trading Program
                                      500
                                      600
Ozone Season NOx Trading Program
                                     1,300
                                     1,500
Note: EPA has provided allowance price projections rounded to the nearest hundred dollars because the model's point estimates assume perfect foresight and therefore do not reflect the price-discovery process that will occur as the marketplace evaluates these new allowances.

7.7	Projected Generation Mix
      Table 7-13 and Figure 7-5 show the generation mix with the Transport Rule.  Coal-fired generation and natural-gas-fired generation are projected to remain relatively unchanged because of the phased-in nature of the Transport Rule, which allows industry the appropriate amount of time to install the necessary pollution controls.  Additionally, the operating costs of complying coal-fired units are not so affected as to result in major changes in the electricity generation mix.  Both the base case and the Transport Rule case show shifts away from oil and natural gas generation and toward increased coal generation between 2012 and 2014.

Table 7-13.  Generation Mix with the Base Case (No Further Controls) and with Transport Rule, Contiguous US (Thousand GWh)

                                     2009
                                     2012
                                     2014

                                  Historical
                                     Base
                                      TR
                               Change from Base
                                Percent Change
                                     Base
                                      TR
                               Change from Base
                                Percent Change
Coal
                                     1,754
                                     1,958
                                     1,935
                                      -23
                                     -1.2%
                                     2,017
                                     1,978
                                      -39
                                     -1.9%
Oil
                                      29
                                     0.09
                                     0.09
                                     0.00
                                     -2.2%
                                     0.10
                                     0.11
                                     0.01
                                     5.8%
Natural Gas
                                      917
                                      721
                                      739
                                      18
                                     2.5%
                                      686
                                      714
                                      28
                                     4.1%
Nuclear
                                      799
                                      812
                                      812
                                       0
                                     0.0%
                                      822
                                      829
                                       7
                                     0.8%
Hydroelectric
                                      272
                                      281
                                      282
                                       1
                                     0.2%
                                      287
                                      286
                                      -1
                                     -0.4%
Non-hydro Renewables
                                      143
                                      233
                                      239
                                       6
                                     2.7%
                                      250
                                      250
                                       1
                                     0.2%
Other
                                       0
                                      35
                                      35
                                      0.0
                                     0.0%
                                      45
                                      45
                                      0.6
                                     1.3%
Total
                                     3,914
                                     4,041
                                     4,043
                                       2
                                     0.0%
                                     4,107
                                     4,102
                                      -4
                                     -0.1%

Note: Numbers may not add due to rounding.
Source: 2009 data from EIA Electric Power Annual 2009, Table 2.1 and Net Generation by State by Type of Producer by Energy Source (EIA-906); 2012 and 2014 projections are from the Integrated Planning Model run by EPA, 2011.

Figure 7-5.  Generation Mix with the Base Case (No Further Controls) and with Transport Rule

Source: Integrated Planning Model run by EPA, 2011.

      Relative to the base case, about 4.8 GW of coal-fired capacity is projected to be uneconomic to maintain (less than 2 percent of all coal-fired capacity in the Transport Rule states, or about 1% of all capacity nationally) by 2014.  Notably, about 3 GW of capacity would have closed by 2014 in the base case without the Transport Rule (for a total of 7.8 GW of retirement in 2014 due to baseline economic conditions and the Transport Rule) .  Uneconomic units, for the most part, are small and infrequently used generating units that are dispersed throughout the states covered in the Transport Rule.  In practice, units projected to be uneconomic to maintain may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  EPA modeling is unable to distinguish between these potential outcomes.  IPM can only predict that specific generating units are uneconomic to maintain, based on their fuel, operating and fixed costs, and whether they are needed to meet both demand and reliability reserve requirements.

7.8	Projected Capacity Additions
      In addition, EPA projects that most future growth in electric demand will be met with new natural gas-fired capacity (see Table 7-14) in both the base and Transport Rule scenarios.

Table 7-14.  Total Generation Capacity by 2014 (GW)

                                     2010
                                     Base
                                      TR
                                    Change
Pulverized Coal
                                      317
                                      312
                                      307
                                      -5
Natural Gas Combined Cycle
                                      201
                                      205
                                      205
                                       0
Other Oil/Gas
                                      253
                                      232
                                      233
                                       0
Non-Hydro Renewables
                                      31
                                      70
                                      70
                                       0
Hydro
                                      99
                                      99
                                      99
                                       0
Nuclear
                                      102
                                      103
                                      104
                                       1
Other
                                       5
                                      81
                                      85
                                       4
Total
                                     1,009
                                     1,103
                                     1,103
                                       0

Source: 2010 data from EPA's NEEDS v4.10.  Projections from Integrated Planning Model run by EPA.
Note: "Renewables" include biomass, geothermal, solar, and wind electric generation capacity.

7.9	Projected Coal Production for the Electric Power Sector
      Coal production for electricity generation is expected to increase relative to current levels, with or without the Transport Rule (see Table 7-15).  Under the Transport Rule, EPA projects coal production for use by the power sector will increase above 2009 levels by 21 million tons in 2012 and by a further 14 million tons in 2014, as opposed to 30 million tons in 2012 and a further 26 million tons in 2014 without the Transport Rule in place.
      The Transport Rule will encourage the installation of new controls and operation of existing pollution controls for SO2 and NOx removal.  Many of these pollution controls can achieve SO2 removal rates of 95 percent or greater, which allows industry to rely more heavily on local bituminous coal in the eastern and central parts of the country that has a higher sulfur content and is less expensive to transport than western subbituminous coal.  Note, for example, the projected increase in Appalachian coal production under the Transport Rule in 2014, which contrasts with the projected 11 million ton decrease over that time in the absence of the rule.  Production of low-sulfur western coal also increases as a result of the Transport Rule in both 2012 and 2014, as some units pursue fuel-switching to lower-sulfur coals to achieve emission reductions.  Notwithstanding the Transport Rule, coal production in the interior region is still projected to increase more than 60% above 2009 levels by 2014.

Table 7-15.  Coal Production for the Electric Power Sector with the Base Case (No Further Controls) and with the Transport Rule (Million Tons)

                                     2009
                                     2012
                                     2014
Supply Area
                                  Historical
                                     Base
                                      TR
                               Change from Base
                                     Base
                                      TR
                               Change from Base
Appalachia
                                      246
                                      193
                                      184
                                      -9
                                      182
                                      186
                                       4
Interior
                                      129
                                      209
                                      189
                                      -20
                                      238
                                      210
                                      -27
West
                                      553
                                      544
                                      565
                                      21
                                      554
                                      556
                                       3
Waste Coal
                                      14
                                      14
                                      14
                                       0
                                      14
                                      14
                                       0
Imports
                                      19
                                      31
                                      31
                                       0
                                      30
                                      30
                                       0
Total
                                      961
                                      991
                                      983
                                      -8
                                     1,017
                                      996
                                      -21
Source: Production: U.S. Energy Information Administration (EIA data), Coal Distribution -- Annual (Final), web site  http://www.eia.doe.gov/cneaf/coal/page/coaldistrib/a_distributions.html (posted February 18, 2011); Waste Coal: U.S. EIA, Monthly Energy Review, January 2011 Edition, Table 6.1 Coal Overview, web site http://www.eia.doe.gov/emeu/mer/coal.html (posted January 31, 2011).  Imports: U.S. Energy Information Administration (EIA) and U.S. Census.  All projections from Integrated Planning Model run by EPA, 2011.

Figure 7-6.  Total Coal Production by Coal-Producing Region, 2007 (Million Short Tons)

Note: Regional totals do not include refuse recovery
Source: EIA Annual Coal Report, 2007

7.10	Projected Retail Electricity Prices
      Retail electricity prices for the Transport Rule region are projected to increase a small amount with the Transport Rule (see Table 7-16).  Regional retail electricity prices in the eastern half of the country are projected to range from 0.1 to 3 percent higher with the Transport Rule in 2014.  By 2014, retail electricity prices in the regions directly affected by the Transport Rule, on average, are projected to be roughly 0.8 percent higher with the Transport Rule.
Table 7-16.  Projected Regional Retail Electricity Prices with the Base Case (No Further Controls) and with Transport Rule (2007 cents/kWh)

                                     Base
                                Transport Rule
                                Percent Change

                                     2012
                                     2014
                                                                           2020
                                     2012
                                     2014
                                     2020
                                     2012
                                     2014
                                     2020
ECAR
                                      7.4
                                      7.9
                                      8.1
                                      7.7
                                      8.2
                                      8.3
                                     3.0%
                                     3.1%
                                     2.9%
ERCOT
                                      7.8
                                      8.8
                                      8.7
                                      8.1
                                      8.9
                                      8.8
                                     3.4%
                                     0.3%
                                     1.9%
MAAC
                                      8.4
                                      9.4
                                     10.3
                                      8.7
                                      9.5
                                     10.4
                                     4.0%
                                     1.4%
                                     1.2%
MAIN
                                      7.3
                                      7.9
                                      8.4
                                      7.5
                                      8.1
                                      8.4
                                     2.0%
                                     1.7%
                                     0.9%
MAPP
                                      7.8
                                      8.0
                                      7.9
                                      7.8
                                      8.1
                                      7.9
                                     0.4%
                                     0.8%
                                     0.3%
NY
                                     12.5
                                     13.7
                                     13.3
                                     12.8
                                     13.7
                                     13.4
                                     2.5%
                                     0.4%
                                     0.4%
NE
                                     11.4
                                     12.3
                                     11.8
                                     11.7
                                     12.3
                                     11.9
                                     1.8%
                                     -0.1%
                                     0.6%
FRCC
                                      9.5
                                     10.2
                                      9.7
                                      9.6
                                     10.2
                                      9.8
                                     1.1%
                                     -0.2%
                                     0.4%
STV
                                      7.7
                                      7.9
                                      7.8
                                      7.8
                                      7.9
                                      7.8
                                     0.9%
                                     0.5%
                                     0.4%
SPP
                                      7.4
                                      7.6
                                      7.4
                                      7.4
                                      7.6
                                      7.4
                                     0.8%
                                     0.1%
                                     -0.1%
PNW
                                      6.9
                                      7.1
                                      6.9
                                      6.9
                                      7.1
                                      6.9
                                     0.5%
                                     0.0%
                                     0.0%
RM
                                      8.6
                                      9.1
                                      9.4
                                      8.7
                                      9.2
                                      9.4
                                     0.7%
                                     0.2%
                                     0.3%
CALI
                                     12.7
                                     13.0
                                     12.5
                                     12.9
                                     13.0
                                     12.5
                                     0.8%
                                     0.0%
                                     0.2%
TR Region Average
                                      8.5
                                      9.2
                                      9.2
                                      8.7
                                      9.3
                                      9.3
                                     2.2%
                                     0.8%
                                     1.0%
Contiguous U.S. Average
                                      8.5
                                      9.0
                                      8.9
                                      8.6
                                      9.0
                                      9.0
                                     1.7%
                                     0.8%
                                     0.9%
Source: EPA's Retail Electricity Price Model.

Figure 7-7.  Retail Price Model Regions

7.11	Projected Fuel Price Impacts
      The impacts of the Transport Rule on coal prices and natural gas prices are shown below in Tables 7-17 and 7-18.  Overall, the projected average coal price decrease is related to the small decrease in projected coal demand.  Projected gas price changes are directly related to the projected increase in natural gas consumption under the Transport Rule.
	IPM modeling of natural gas prices uses both short- and long-term price signals to balance supply of and demand in competitive markets for the fuel across the modeled time horizon.  As such, it should be understood that the pattern of IPM natural gas price projections over time is not a forecast of natural gas prices incurred by end-use consumers at any particular point in time.  The natural gas market in the United States has historically experienced significant price volatility from year to year, between seasons within a year, and even sees major price swings during short-lived weather events (such as cold snaps leading to short-run spikes in heating demand).  These short-term price signals are fundamental for allowing the market to successfully align immediate supply and demand needs; however, end-use consumers are typically shielded from experiencing these rapid fluctuations in natural gas prices by retail rate regulation and by hedging through longer-term fuel supply contracts.  IPM assumes these longer-term price arrangements take place "outside of the model" and on top of the "real-time" shorter-term price variation necessary to align supply and demand.  Therefore, the model's natural gas price projections should not be mistaken for traditionally experienced consumer price impacts related to natural gas, but a reflection of expected average price changes over the time period 2012 to 2030.
	For this analysis, in order to represent a natural gas price evolution that end-use consumers can anticipate under retail rate regulation and/or typical hedging behavior, EPA is displaying the weighted average of IPM's natural gas price projections for the 2012-2030 time horizon (see Table 7-18).  In that framework, consumer natural gas price impacts are anticipated to range from 0.2% to 0.3% based on consumer class in response to the Transport Rule.

Table 7-17.  Average Minemouth and Delivered Coal Prices with the Base Case and with the Transport Rule (2007$/MMBtu)

                                     2012
                                     2014

                                     2007
                                     Base
                                      TR
                           Percent Change from Base
                                     Base
                                      TR
                           Percent Change from Base
Minemouth
                                     1.27
                                     1.35
                                     1.29
                                     -4.3%
                                     1.37
                                     1.35
                                     -1.7%
Delivered
                                     1.76
                                     2.08
                                     2.05
                                     -1.4%
                                     2.12
                                     2.10
                                     -0.9%

Source: Historical data from EIA AEO 2010 Reference Case Table 15 (Coal Supply, Distribution, and Prices); projections from the Integrated Planning Model run by EPA, 2011.

Table 7-18.  2012-2030 Weighted Average Henry Hub and Delivered Natural Gas Prices with the Base Case and with the Transport Rule (2007$/MMBtu)

                                     Base
                                      TR
                           Percent Change from Base
Henry Hub
                                     5.32
                                     5.34
                                     0.4%
Delivered - Electric Power
                                     5.60
                                     5.62
                                     0.3%
Delivered - Residential
                                     10.97
                                     10.99
                                     0.2%

Source: Projections from the Integrated Planning Model run by EPA (2011) adjusted to Henry Hub prices using historical data from EIA AEO 2011 reference case to derive residential prices.

7.12	Key Differences in EPA Model Runs for Transport Rule Modeling Geography
	As previously stated, the emissions, cost, air quality, and benefits analyses done for the Transport Rule are from a modeling scenario that requires annual SO2 and NOx reductions in 23 states and ozone season NOx requirements in 26 states (See Figure 7-1).  This modeling differs from the final Transport Rule because it includes ozone season NOX requirements for six states (Iowa, Kansas, Michigan, Missouri, Oklahoma, and Wisconsin) that the final Transport Rule does not cover. (As discussed in the preamble to the final rule, EPA is issuing  a supplemental proposal to request comment on inclusion of these six states).

7.13	Projected Primary PM Emissions from Power Plants
      IPM does not endogenously model primary PM emissions from power plants.  These emissions are calculated as a function of IPM outputs, emission factors and control configuration.  IPM-projected fuel use (heat input) is multiplied by PM emission factors (based in part on the presence of PM-relevant pollution control devices) to determine PM emissions.  Primary PM emissions are calculated by adding the filterable PM and condensable PM emissions.
      Filterable PM emissions for each unit are based on historical information regarding existing emissions controls and types of fuel burned and ash content of the fuel burned, as well as the projected emission controls (e.g., scrubbers and fabric filters).
      Condensable PM emissions are based on plant type, sulfur content of the fuel, and SO2 and PM control configurations.  Although EPA's analysis is based on the best available emission factors, these emission factors do not account for the potential changes in condensable PM emissions due to the installation and operation of SCRs.  The formation of additional condensable PM (in the form of SO3 and H2SO4) in units with SCRs depends on a number of factors, including coal sulfur content, combustion conditions and characteristics of the catalyst used in the SCR, and is likely to vary widely from unit to unit.  SCRs are generally designed and operated to minimize increases in condensable PM.  This limitation means that IPM post-processing is potentially underestimating condensable PM emissions for units with SCRs.  In contrast, it is possible that IPM post-processing overestimates condensable PM emissions in a case where the unit is combusting a low-sulfur coal in the presence of a scrubber.
      EPA plans to continue improving and updating the PM emission factors and calculation methodologies.  For a more complete description of the methodologies used to post-process PM emissions from IPM, see "IPM ORL File Generation Methodology" (March, 2011).

7.14	Analysis Approach and Limitations
      EPA's modeling is based on its best judgment for various input assumptions that are uncertain.  Assumptions for future fuel prices and electricity demand growth deserve particular attention because of the importance of these two key model inputs to the power sector.  As a general matter, the Agency selects the best available information from available engineering studies of air pollution controls and has set up what it believes is the most reasonable modeling framework for analyzing the cost, emission changes, and other impacts of regulatory controls.
      The annualized cost estimates of the private compliance costs that are provided in this analysis are meant to show the increase in production (engineering) costs to the power sector of the Transport Rule selected remedy and any alternatives.  In simple terms, the private compliance costs that are presented are the annual increase in revenues required for the industry to be as well off after the Transport Rule is implemented as before.  To estimate these annualized costs, EPA uses a conventional and widely-accepted approach that is commonplace in economic analysis of power sector costs for estimating engineering costs in annual terms.  For estimating annualized costs, EPA has applied a capital recovery factor (CRF) multiplier to capital investments and added that to the annual incremental operating expenses.  The CRF is derived from estimates of the cost of capital (private discount rate), the amount of insurance coverage required, local property taxes, and the life of capital.  The private compliance costs presented earlier are EPA's best estimate of the direct private compliance costs of the Transport Rule.
      The annualized cost of the Transport Rule, as quantified here, is EPA's best assessment of the cost of implementing the Transport Rule.  These costs are generated from rigorous economic modeling of changes in the power sector due to the Transport Rule.  This type of analysis using IPM has undergone peer review and federal courts have upheld regulations covering the power sector that have relied on IPM's cost analysis.
      The direct private compliance cost includes, but is not limited to, capital investments in pollution controls, operating expenses of the pollution controls, investments in new generating sources, and additional fuel expenditures.  EPA believes that the cost assumptions used for the Transport Rule reflect, as closely as possible, the best information available to the Agency today.  The relatively small cost associated with monitoring emissions, reporting, and record keeping for affected sources is not included in these annualized cost estimates, but EPA has done a separate analysis and estimated the cost to be approximately $26.2 million (see Section 9.3., Paperwork Reduction Act, of this RIA for more information).
      Cost estimates for the Transport Rule are based on results from ICF's Integrated Planning Model.  The model minimizes the costs of producing electricity (including abatement costs) while meeting load demand and other constraints (full documentation for IPM can be found at http://www.epa.gov/airmarkets/progsregs/epa-ipm and in the document titled: "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule").  The structure of the model assumes that the electric utility industry will be able to meet environmental emission caps at least cost.  Montgomery (1972) has shown that this least cost solution corresponds to the equilibrium of an emission permit system.  See also Atkinson and Tietenburg (1982), Krupnick et al. (1980), and McGartland and Oates (1985).  However, to the extent that transaction and/or search costs, combined with institutional barriers, restrict the ability of utilities to exhaust all the gains from emission trading, costs are underestimated by the model.  Utilities in the IPM model also have "perfect foresight."  To the extent that utilities misjudge future conditions affecting the economics of pollution control, costs may be understated as well.
      The "perfect foresight" of the model is also relevant in the context of the assurance provisions required in the Transport Rule.  Because of the sizeable penalties associated with violating assurance provisions, EPA believes it will be economical for units to comply with the provisions.  EPA modeled these provisions, which restrict emissions from a state to the budget plus variability limits on a 1-year basis, as state-specific emissions caps set at the budget plus average variability, or state assurance level.  The Power Sector Variability Technical Support Document contains further details on these assurance provisions.
      Modeling the assurance provisions as caps means that the model must meet the same limit each year, but it also allows the model to optimize with perfect foresight the present and future limits.   The model minimizes production costs while meeting required generation and reserve margin, but sources in reality may choose to make greater emission reductions than required in exchange for more certainty about emissions variability.  IPM captures the cost associated with making required reductions in each state, but because of its "perfect foresight," the model likely cannot capture the true benefit to sources of having a range of allowed variability.
      From another vantage point, this modeling analysis does not take into account the potential for advancements in the capabilities of pollution control technologies for SO2 and NOx removal as well as reductions in their costs over time after 2014.  Market-based cap and trade regulation serves to promote innovation and the development of new and cheaper technologies.  As an example, cost estimates of the Acid Rain SO2 trading program by Resources for the Future (RFF) and MIT's Center for Energy and Environmental Policy Research (CEEPR) have been as much as 83 percent lower than originally projected by the EPA (see Carlson et al., 2000; Ellerman, 2003).  It is important to note that the original analysis for the Acid Rain Program done by EPA also relied on an optimization model like IPM.  Ex ante, EPA cost estimates of roughly $2.7 to $6.2 billion in 1989 were an overestimate of the costs of the program in part because of the limitation of economic modeling to predict technological improvement of pollution controls and other compliance options such as fuel switching.  Ex post estimates of the annual cost of the Acid Rain SO2 trading program range from $1.0 to $1.4 billion.  Harrington et al. have examined cost analyses of EPA programs and found a tendency for predicted costs to overstate actual implementation costs in market-based programs (Harrington, Morgenstern, and Nelson, 2000).  In recognition of this, EPA's mobile source program uses adjusted engineering cost estimates of pollution control equipment and installation costs to account for this fact, which EPA has not done in this case.  The Agency is considering approaches to make this adjustment in the future, or at least to be able to provide a sense of the rough amount by which costs could be overstated in the analysis that has occurred.
      EPA's latest update of IPM incorporates state rules or regulations and various NSR settlements adopted through December, 2010.  Documentation for IPM can be found at http://www.epa.gov/airmarkets/progsregs/epa-ipm and in the document titled: " Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule."  Any state or settlement action since that time has not been accounted for in our analysis in this chapter.
      As configured in this application, IPM does not take into account demand response (i.e., consumer reaction to electricity prices).  The increased retail electricity prices shown in Table 7-16 would prompt end users to curtail (to some extent) their use of electricity and encourage them to use substitutes.  The response would lessen the demand for electricity, resulting in electricity price increases slightly lower than IPM predicts, which would also reduce generation and emissions.  Because of demand response, certain unquantified negative costs (i.e., savings) result from the reduced resource costs of producing less electricity because of the lower quantity demanded.  To some degree, these saved resource costs will offset the additional costs of pollution controls and fuel switching that we would anticipate with the Transport Rule.  Although the reduction in electricity use is likely to be small, the cost savings from such a large industry is not insignificant.  EIA analysis examining multi-pollutant legislation under consideration in 2003 indicates that the annualized costs of the Transport Rule may be overstated substantially by not considering demand response, depending on the magnitude and coverage of the price increases.
      On balance, after consideration of various unquantified costs (and savings that are possible), EPA believes that the annual private compliance costs that we have estimated are more likely to overstate the future annual compliance costs that industry will incur, rather than understate those costs.
7.15	Significant Energy Impact
      The Transport Rule has a significant impact according to E.O. 13211: Actions that Significantly Affect Energy Supply, Distribution, or Use.  Under the provisions of this final rule, EPA projects that approximately 4.8 GW of additional coal-fired generation may be removed from operation by 2014.  In practice, however, the units projected to be uneconomic to maintain may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  These units are predominantly small and infrequently-used generating units dispersed throughout the area affected by the rule.  If current forecasts of either natural gas prices or electricity demand were revised in the future to be higher, that would create a greater incentive to keep these units operational.
      EPA estimates that average retail electricity price could increase in the contiguous U.S. by about 1.7 percent in 2012 and 0.8 percent in 2014.  This is generally less of an increase than often occurs with fluctuating fuel prices and other market factors.  Related to this, EPA projects limited impacts on coal and gas prices.  The average delivered coal price decreases by about 1.4 percent in 2012 and 0.9 percent in 2014 relative to the base case as a result of decreased coal demand and shifts in the type of coal demanded.  As discussed above in section 7.11, EPA also projects that electric power sector-delivered natural gas price will increase by about 0.3% over the 2012-2030 timeframe and that natural gas use for electricity generation will increase by approximately 200 billion cubic feet (BCF) by 2014.  These impacts are well within the range of price variability that is regularly experienced in natural gas markets.  Finally, under the Transport Rule, EPA projects that coal production for use by the power sector will increase above 2009 levels by 21 million tons in 2012 and a further 14 million tons in 2014, as opposed to 30 million tons in 2012 and a further 26 million tons in 2014 without the Transport Rule in place.  The Transport Rule is not projected to impact production of coal for uses outside the power sector (e.g., export, industrial sources), which represent approximately 6% of total coal production in 2009.  EPA does not believe that this rule will have any other impacts (e.g., on oil markets) that exceed the significance criteria.
      EPA believes that a number of features of the rulemaking serve to reduce its impact on energy supply.  First, the trading component of the Transport Rule provides considerable flexibility to the power sector and enables industry to comply with the emission reduction requirements in the most cost-effective manner, thus minimizing overall costs and the ultimate impact on energy supply.  Second, the emission budgets for SO2 are set in two phases, providing adequate time for EGUs to install pollution controls ahead of the second phase.  In addition, both the operational flexibility of trading and the ability to bank allowances for future years help industry plan for and ensure reliability in the electrical system.

7.16	References
Atkinson, S., and T. Tietenberg.  1982.  "The Empirical Properties of Two Classes of Design for Transferable Discharge Permit Markets."  Journal of Environmental Economics and Management 9:101-121
Carlson, Curtis, Dallas R. Burtraw, Maureen, Cropper, and Karen L. Palmer.  2000.  "Sulfur Dioxide Control by Electric Utilities: What Are the Gains from Trade?"  Journal of Political Economy 108(#6):1292-1326.
Ellerman, Denny.  January 2003.  Ex Post Evaluation of Tradable Permits: The U.S. SO2 Cap-and-Trade Program.  Massachusetts Institute of Technology Center for Energy and Environmental Policy Research.
EIA Annual Coal Report 2008.  DOE/EIA-0584 (2008).  Available at: http://www.eia.doe.gov/cneaf/coal/page/acr/acr_sum.html
EIA Annual Energy Outlook 2003.  DOE/EIA-0383 (2003).  Available at: http://www.eia.doe.gov/oiaf/archive/aeo03/index.html
EIA Electric Power Annual 2008.  DOE/EIA-0348 (2008).  Available at: http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.htm
EIA Electric Power Monthly March 2010 with Data for December 2009.  DOE/EIA-0226 (2010/03).  Available at: http://www.eia.doe.gov/cneaf/electricity/epm/epm_sum.html
Freme, Fred.  2009.  U.S. Coal Supply and Demand: 2008 Review.  EIA.  Available at: http://www.eia.doe.gov/cneaf/coal/page/special/tbl1.html
Harrington, W., R.D. Morgenstern, and P. Nelson.  2000.  "On the Accuracy of Regulatory Cost Estimates."  Journal of Policy Analysis and Management 19(2):297-322.
Keohane, Nathaniel O.  2009.  "The Technocratic and Democratic Functions of the CAIR Regulatory Analysis."  In Reforming Regulatory Impact Analysis, eds. Winston Harrington, Lisa Heinzerling, and Richard D. Morgenstern, 33 - 55.  Washington, DC: Resources for the Future.
Krupnick, A., W. Oates, and E. Van De Verg.  1980.  "On Marketable Air Pollution Permits: The Case for a System of Pollution Offsets."  Journal of Environmental Economics and  Management 10:233-47.
Manson, Nelson, and Neumann.  2002.  "Assessing the Impact of Progress and Learning Curves on Clean Air Act Compliance Costs."  Industrial Economics Incorporated.
McGartland, A., and W. Oates.  1985.  "Marketable Permits for the Prevention of Environmental Deterioration." Journal of Environmental Economics and Management 12:207-228.
Montgomery, W. David.  1972.  "Markets in Licenses and Efficient Pollution Control Programs."  Journal of Economic Theory 5(3):395-418.
Wagner, Wendy E.  2009.  "The CAIR RIA: Advocacy Dressed Up as Policy Analysis."  In Reforming Regulatory Impact Analysis, eds. Winston Harrington, Lisa Heinzerling, and Richard D. Morgenstern, 56 - 81.  Washington, DC: Resources for the Future.

Chapter 8
         MaCROEconomic and Employment Impacts

8.1	Partial Equilibrium Analysis (Multiple Markets)
In this chapter, we provide estimates of the economic impacts to industry sectors outside the electric power industry and social costs associated with the selected remedy.  Economic impacts presented in this chapter are changes in price and outputs for affected products from a large number of industry sectors (100).  Social costs are estimates of the costs to society associated with the control and administrative costs presented in Chapter 7.  Such costs are estimated from changes in consumer and producer surplus, as discussed in more detail below.
Our partial equilibrium analysis uses a market model that simulates how stakeholders (consumers and industries) might respond to the additional regulatory program costs. In this section, we provide an overview of the economic model and the results for a short-run economic impact analysis (in this case, for 2014).  While the Multimarket Model has not been peer-reviewed, EPA plans to peer-review the model in the near future.  More details on the economic model, the results, and data used by the model can be found in Appendix B.
8.1.1	Overview
Although several tools are available to estimate social costs, current EPA guidelines suggest that multimarket models "...are best used when potential impacts on related markets might be considerable" and modeling using a computable general equilibrium model is not available or practical (EPA, 2010, p. 9-21). Other guides for environmental economists offer similar advice (Berck and Hoffmann, 2002; Just, Hueth, and Schmitz, 2004). Multimarket models focus on "short-run" time horizons and measure a policy's near-term or transition costs as stated in the EPA Economic Resource Document (EPA, 1999). These models have greater levels of aggregation than detailed partial equilibrium models of compliance for individual sectors, like IPM, but represent more sectors of the economy.
A linked partial equilibrium model is useful for evaluating relative economic impacts across related markets and providing a measure of consumer and producer surplus losses.   It may not be sufficient for fully estimating social costs, just as a single market model may not be appropriate for fully estimating social costs. Generally speaking, the smaller the effect of a regulation on partial-equilibrium measures of social welfare such as consumer and producer surplus, the more accurately those estimates reflect the true social cost. However, a transition or short-term evaluation using a partial equilibrium model does not explicitly account for resources to be reallocated across sectors according to relative price changes (although the multi-market model does account for certain resource constraints and the employment of intermediate inputs). Furthermore, these models (if static) may not capture how resource use and consumption shifts over time in response to the regulation, which may be accounted for with a dynamic computable general equilibrium model.  Therefore, we use care in referring to the estimate of total change in surplus coming out of the Multimarket model as a social cost.  For regulations with a relatively modest impact on the economy, however, such as this final rule, the change in surplus estimated by this model may provide a reasonable approximation of the social cost.
Our multimarket model contains the following features:
         Industry sectors and benchmark data set
            -100 industry sectors
            -multiple benchmark years
         Economic behavior
            -industries respond to regulatory costs by changing production rates
            -market prices rise and fall to reflect higher energy and other non-energy material -costs and changes in demand
            -customers respond to price increases and consumption falls
         Model scope
            -100 sectors are linked with each other based on their use of energy and other non-energy materials. For example, the construction industry is linked with the petroleum, cement, and steel industries and is influenced by price changes that occur in each sector. The links allow EPA to account for indirect effects the regulation has on related markets.
            -production adjustments influence employment levels
            -international trade (imports/exports) responds to domestic price changes
         Model time horizon ("short run") for a single period (2015)
            -fixed production resources (e.g., capital) lead to an upward-sloping industry supply function
            -firms cannot alter certain input mixes; there is no substitution among intermediate production inputs
            -there is no explicit labor market (a real wage and labor supply is not determined within the model)
            -investment and government expenditures are fixed.
            Although the model is intended to examine transition or short-term effects of this rulemaking, the results may be muted due to the use of annualized capital cost as an input to the model rather than the total capital cost.
         Labor  and Capital Markets and Pre-existing Distortions in Other Markets
            Unlike CGE models, our multimarket model does not include a national labor or capital market.  As a result, we do not estimate real wage changes, changes in labor /leisure choices, or savings and investment decisions within the model.  Therefore we do not consider whether policies interact with existing distortions, particularly tax distortions in a ways that increase or decrease estimates of the social cost.  Since savings and investment decisions are not modeled, social costs associated with capital stock changes are also not considered.
      Although the model is intended to examine transition or short-term effects of this rulemaking, the estimate of the short-term effects may be understated due to the way the model accounts for changes in capital demand. The cost of new capital associated with the rule is accounted for by imposing an increase in the annualized capital cost rather than the total capital cost in the year of analysis. Additionally, using an economic impact model that constrains the physical capital stock to be fixed will not fully depict the social costs of an adjustment to a post-policy equilibrium as discussed in the EPA Economics Guidelines.
      The own-price elasticities used by the Multimarket Model are drawn from secondary sources, as fully described in Appendix B.  While the Multimarket Model is a short-run model that examines transitional costs that arise as a result of a new regulation, the estimation methods used by the secondary sources generally assume that people and firms have more flexibility to adjust consumption and production decisions than they would have in a short-run model. Consequently, use of these elasticities within the Multimarket Model may in some cases lead to estimates of larger market output changes than would actually occur in the short-run, all other things being equal.