2. Compliance and Deployment of Pollution Control Technologies 

The power industry will undertake a diverse set of actions 

to comply with the Transport Rule at the start of 2012 and 

another set of actions when companies in Group 1 states comply 

with more stringent SO2 budgets at the start of 2014. In 2012, 

the industry will largely meet the rule’s NOX requirements by: 

operating an extensive existing set of combustion and postcombustion controls on fossil fuel-fired generators; dispatching 

lower emitting units more often; and installing and operating a 

limited amount of relatively simple NOX pollution controls in 

states not previously subject to CAIR. For the SO2 requirements, 

EPA anticipates at a minimum that coal-fired generators will 

operate the substantial capacity of advanced pollution controls 

already in place or scheduled for 2012 use; some units will also 

elect to burn lower-sulfur coals; and the fleet will increase 

dispatch from lower-sulfur-emitting units as well as from 

natural gas-fired generators. EPA provides a more detailed 

explanation below of how fuel switching to lower sulfur coals 

factored in to the design of the final Transport Rule. 

 By 2014, EPA’s budgets under the Transport Rule will 

sustain previous NOX and SO2 reductions as well as account for 

reductions from additional advanced NOX and SO2 controls that are 

driven by other state and federal requirements. In addition to 
these reductions, companies in Group 1 states are also projected 

to add a limited amount of advanced SO2 controls in 2014 that 

will be discussed below. 

EPA’s expectations are supported by the IPM analysis 

reported in this rule’s RIA (see Chapter 7). Notably, since EPA 

has established a cap and trade control system for lowering NOX

and SO2 emissions, individual owners and operators of covered 

units have some flexibility in meeting the program’s 

requirements as needed and are free to find alternative ways to 

comply. The RIA clearly shows a viable known pathway for owners 

and operators to comply at reasonable costs, although it is not 

the only compliance pathway possible under this flexible 

regulation that could deliver the emission reductions required 

under the rule. Notably, by 2014 and beyond, the power industry 

may also augment the projected compliance efforts with programs 

aimed at improving energy efficiency. 

Table VII.C.2-1 shows EPA’s projection of the amount of 

existing coal-fired generating capacity in gigawatts (GW) that 

may retrofit various systems for compliance with this rule. 

Table VII.C.2-1 Projected Potential Air Pollution Control (APC) 

Retrofits for Transport Rule1

                                                           

1

 GW: gigawatts of capacity retrofitted; FGD: flue gas 

desulfurization (SO2 control); DSI: dry sorbent injection (SO2
Capacity 

retrofitted by:

Wet FGD Dry FGD DSI SCR LNB/OFA 

Improvements

January 1, 2012     10 GW

January 1, 2014 5.7 GW 0.2 GW 3.0 GW 0 GW 

EPA received proposal comments expressing a concern about 

the feasibility of deploying retrofit air pollution control 

(APC) technologies in the time frames available between the 

final date of this rule and the compliance dates. As discussed 

below, EPA believes that it is feasible for the electric power 

sector and its APC supply chain to either make most of the 

projected retrofits in time to meet the 2012 and 2014 compliance 

deadlines, or to comply by other means. 

a. 2012 Power Industry Compliance 

EPA’s analysis of emission reductions available in 2012 

assumes year-round operation of existing post-combustion 

pollution controls in states covered for PM2.5 and ozone-season 

operation of NOX post-combustion controls in states covered for 

ozone. EPA also modeled emission reductions available in 2012 

at the $500/ton threshold for SO2, $500/ton for annual NOX, and 

$500/ton for ozone-season NOX. 

                                                                                                                                                                                               

control); SCR: selective catalytic reduction (NOX control); 

LNB/OFA: low-NOX burner and/or overfire air (NOX controls) 
For SO2, EPA believes that reductions associated with the 

following methods of control are available and will be used as 

compliance strategies to meet the 2012/2013 budgets: 1) 

operation of existing controls year-round in PM2.5 states, 2) 

operation of scrubbers that are currently scheduled to come 

online by 2012, 3) some sources switching to lower-sulfur coal 

(see section VII.C.2.c that follows), and 4) changes in dispatch 

and generation shifting from higher emitting units to lower 

emitting units. EPA modeling and selection of a $500/ton cost 

threshold includes all existing and planned controls operating 

year round (items 1 and 2). It also reflects an amount of coal 

switching and generation shifting that can be achieved for 

$500/ton. This set of expected actions was confirmed in the 

detailed modeling of EPA’s final remedy in the RIA and can be 

reviewed there.

Of the 240 GW of coal capacity in the Transport Rule region 

covered for fine particles, approximately 110 GW – more than 45

percent -- had existing advanced pollution control for SO2

already in place in 2010, including scrubbers (FGD), dry sorbent 

injection (DSI), or circulating fluidized bed boilers. Of this 

controlled coal capacity, EPA expects a significant portion will 

improve emission rates through either increased use of control 

technology and/or additional fuel switching. EPA notes that an 
additional 39 GW of advanced SO2 controls in the region are 

scheduled to come online over the 2010-2012 timeframe and will 

also assist in meeting 2012 emission reduction requirements. 

Thus, by 2012 more than half of affected coal capacity – 152 GW

- will be operating with advanced SO2 control equipment. 

Additionally, EPA expects approximately 40 GW of uncontrolled 

coal capacity in the region to take advantage of the existing 

coal supply infrastructure, possibly switching coal use or coal 

blending behaviors to make cost-effective reductions in SO2

emission rates where economic to respond to the Transport Rule 

2012 emission reduction requirements. 

EPA notes that approximately 136 GW of the 240 GW – more 

than 56 percent -- of coal capacity in the Transport Rule region 

covered for fine particles had existing advanced pollution 

control for NOX already in place in 2010, including selective 

catalytic reduction (SCR), selective non-catalytic reduction 

(SNCR), or circulating fluidized bed boilers. Of this capacity, 

EPA anticipates a significant portion will improve their NOX

emission rate through increased operation of these existing 

controls. Additionally, EPA notes that an additional 21 GW of 

SCR and 4 GW of enhanced combustion controls (including low-NOX

burners and overfire air) are scheduled to come online in the 

region during the 2010-2012 timeframe, bringing the total 
region’s coal capacity operating with NOX emissions reduction 

technology to 158 GW (more than 65 percent of total coal 

capacity in the Transport Rule fine particle region). EPA also 

projects that approximately 13 GW of coal capacity will make 

some reduction in their NOx emission rates by enhancing

performance of existing combustion controls or SNCR or by fuel 

switching.

In the Transport Rule states covered under the ozone-season 

program, approximately 145 GW of the 260 GW (more than 55 

percent) of coal capacity had existing NOX control technology in 

place in 2010. EPA expects a significant portion of that 

capacity to achieve emission reductions during the 2012 ozoneseason through improved operation of SCR. Additionally, in the 

Transport Rule ozone region there will be approximately 21 GW of 

additional advanced NOX control installations and 7 GW of 

additional combustion control improvements or installations 

coming online during the 2010 to 2012 time frame. EPA projects 

that 17 GW of coal capacity in the Transport Rule ozone region

will reduce NOX emission rates by enhancing performance of 

existing combustion controls or SNCR or by fuel switching.

For NOX, EPA has also concluded that it is appropriate to 

require reductions through a limited amount of combustion 

control improvements, and in some cases, retrofits such as lowFormatted: Subscript
NOX burners (LNB) and/or overfire air (OFA). EPA recognizes that 

the 6-month time frame between rule finalization and start of 

the first compliance period would not allow for the installation 

of a major post-combustion NOX control such as SCR. Assumed 

improvements and retrofits for the January 1, 2012 deadline for 

annual NOX reductions therefore only involve the much simpler 

LNB/OFA control modifications or installations. Alternatively, 

some plant owners might choose to achieve NOX reductions in a 

similar time period through an even simpler retrofit - SNCR.2

Although the improvements, and in some cases, installation 

of combustion controls would be an economic means of achieving 

emission reductions, these specific controls are not required 

for compliance purposes under the final Transport Rule remedy. 

Individual sources may comply through other measures (such as 

purchasing additional allowances) in the event that it takes 

more than 6 months for installation of a given combustion 

control. The vast majority of covered sources already have 

combustion controls installed; therefore, the NOX reductions 

associated with these incremental control improvements and 

installations are small. 

                                                           

2 David L. Wojichowski, SNCR System – Design, Installation, and 

Operating Experiencehttp://www.netl.doe.gov/publications/ 

proceedings/02/scr-sncr/ wojichowski-1.pdf
Based on the Transport Rule’s geography, EPA estimates that 

approximately 10 GW of coal-fired units may improve, and in some 

cases, install LNB/OFA specifically in reaction to the Transport 

Rule NOX caps. EPA reflects the effects of these installations 

in the 2012 annual and ozone-season NOX budgets, which would 

yield reductions of approximately 28,000 tons of annual NOX and 

14,000 tons of ozone-season NOX. EPA assumes these controls are 

cost effective at $500/ton and that they should be incentivized 

through budgets given the 2013 attainment deadline for ozone 

areas classified as “serious.” Once installed, LNB/OFA operates 

any time the boiler is fired and thus yields NOX reductions 

beyond the ozone season alone. 

In the proposal’s LNB technical support document,3

 EPA 

observes that LNB and/or OFA installations, burner 

modifications, or other NOX reduction controls would likely have 

to be installed during fall 2011 or spring 2012 outages in order 

to achieve significant reductions for 2012. While this 6-month 

schedule is aggressive, industry has shown that it can be met. 

For example, Limestone Electric Generating Station Unit 2, an 

820 MW tangentially-fired lignite unit, was retrofitted with 

Foster Wheeler’s Tangential Low NOX (TLN3) system in less than 

                                                           

3

 Technical Support Document (TSD) for the Transport Rule, Docket 

ID No. EPA-HQ-OAR-2009-0491, Installation Timing for Low NOX

Burners (LNB)
six months, including engineering, fabrication, delivery and 

installation.4 Harlee Branch Unit 4, a 535 MW cell-fired unit, 

was retrofitted with Riley Power’s low-NOX Dual Air Zone CCV 

burners on a similar schedule.5

 These are tangentially-fired and 

wall-fired units, respectively, representative of the unit types 

that might make LNB/OFA improvements for compliance with this 

rule. Although such 6-month schedules can be achieved on some 

units, under favorable circumstances, historical projects 

suggest a more typical schedule would be 12 to 16 months for the 

contractor’s portion of the work.6

 A plant owner’s project 

planning and procurement work in advance of a contract award 

would typically involve several additional months. On the other 

hand, there are other approaches that can also be implemented in 

a short time frame to achieve significant NOX reduction. As 

mentioned above, relatively simple SNCR systems can be installed 

quickly; and the re-tuning or upgrading of existing combustion 

                                                           

4

 R. Pearce, J. Grusha, Reliant Energy Tangential Low NOX System 

at Limestone Unit 2 Cuts Texas Lignite, PRB and Pet Coke NOX, 

http://www.fwc.com/publications/tech_papers/files/tp_firsys_01_0

2.pdf

5

 B. Courtemanche, et al, Reducing NOX Emissions and 

Commissioning Time on Southern Company Coal Fired Boilers With 

Low NOX Burners and CFD Analysis, 

http://www.babcockpower.com/pdf/t-182.pdf

6

 M. O’Donnell, Babcock & Wilcox Company, (personal 

communication with EPA staff, February 22, 2011)
control systems can often provide significant NOX reductions and 

can be performed quickly.7

As stated above, EPA believes that LNB/OFA modifications or 

retrofits would be possible during the 6-month interim between 

rule signature and the start of the first compliance period, 

particularly for those “early movers” who have initiated LNB 

projects based on the proposed rule. However, as shown in Table 

VII.C.2-2, below, even if all LNB modifications or installations 

are delayed until the beginning of the 2012 ozone season (10 

months from a June 29, 2011 signature), the reductions only 

represent 1 percent of most covered states’ annual NOX budgets, 

and no more than 11 percent of any affected state’s annual NOX

budget. Under such a scenario, these delayed reductions would 

still be well within the 18 percent variability limit applied to 

each state’s annual NOX budget. In light of this limited 

consequence and the supporting material above, EPA includes LNBdriven NOX reductions in both annual and ozone-season NOX budgets 

for 2012. 

                                                           

7 N.C Widmer, et al, Coal Power, October 8, 2009, 

http://www.coalpowermag.com/ops_and_maintenance/ZonalCombustion-Tuning-Systems-Improve-Coal-Fired-BoilerPerformance_226.html
Table VII.C.2-2 Earliest Reductions Assumed from LNB 

Installations in the Transport Rule States Subject to the Annual 

NOX Program* 

 

NOX Reductions 

from LNB 

Operation from 

January - April 

(tons) 

Annual NOX State 

Budget (tons) 

Percent of 

Budget Met by 

Earliest LNB 

Reductions 

Georgia 646 62,010 1% 

Iowa 567 38,335 1% 

Kansas 2,131 30,714 7% 

Minnesota 2,303 29,572 8% 

Nebraska 3,008 26,440 11% 

Region-wide Total 8,656 1,245,869 1% 

*Based on EPA IPM Analysis of Final Transport Rule 

b. 2014 Power Industry Compliance 

EPA projects that compliance with 2014 requirements for NOX

will result largely from operation of existing and future 

controls required by state and other federal requirements, as 

well as the appropriate dispatch of the electric generation 

fleet. EPA does not project additional NOX pollution control 

retrofits aside from about 10 GWs of combustion control 

improvements or retrofits projected for the 2012 compliance 

period. To comply with the rule’s SO2 requirements, EPA projects 

that the power industry will rely on existing controls, operate 

newly installed advanced controls necessary for other binding 
state and federal requirements, rely more on relatively lower 

sulfur coals, and dispatch lower-emitting generation units. In 

Group 1 states, industry is projected to increase switching to 

lower sulfur coals and install a limited amount of additional 

scrubbers and other advanced pollution control technology. 

EPA’s assessment of the industry’s ability to install SO2

pollution controls in 2014 and undertake the projected coal 

switching follows below. 

EPA’s modeling of least-cost compliance with the state 

budgets under the Transport Rule projects approximately 5.9 GW 

of FGD systems and lesser amounts of other technologies will be 

retrofitted by 2014 for compliance with the Transport Rule.8,9

 

                                                           

8 Nearly all of the 5.9 GW of FGD retrofits are comprised by some 

12 units at 7 plants (Beckjord, Muskingum River, Homer City, 

Rockport, Kammer, Danskammer, and Will County). 

9 As noted elsewhere in this preamble, the projected impacts of 

this final rule presented in the preamble do not reflect minor 

technical corrections to SO2 budgets in three states (KY, MI, and 

NY) and assumed preliminary variability limits that were smaller 

than the variability limits finalized in this rule. EPA 

conducted sensitivity analysis factoring in these corrections; 

the results of this analysis include a small increase of about 

700 MW of additional wet FGD retrofit projected for 2014. This 

projected additional retrofitting capacity is already required 

to retrofit under a consent decree and should therefore have 

already conducted advanced retrofit planning. EPA therefore 

believes that this incremental projected retrofit behavior 

(factoring in the technical corrections made after the main 

impact analyses were conducted) is feasible by 2014 for the same 

reasons presented in this section regarding the projected 

retrofit behavior from the main analysis of the final rule. 
EPA’s schedule assumptions for these larger more complex 

projects were developed in an earlier study and mentioned in the 

proposal: 27 months for retrofitted wet FGD and 21 months for 

SCR.10 Note that a dry FGD system, due to its relatively simpler 

configuration and lesser cost, would typically take somewhat 

less time to retrofit than wet FGD. 

As discussed below, EPA believes that its schedule 

assumptions remain reasonable expectations for sources that have 

completed most of their preliminary project planning and can 

quickly make commitments to proceed. These schedules do not 

include the extensive time that some plant owners might spend in 

making a decision on whether or not to retrofit. They do 

include the time needed to make a final confirmation of the type 

of technology to be used at a particular site, to prepare bid 

requests, award contracts, perform engineering, obtain 

construction and operating permits (in parallel with project 

activities), perform construction, tie-in to the existing plant 

systems, and perform integrated systems testing. 

EPA received comments on the proposed rule indicating that 

some past single-unit APC retrofits had considerably longer 

                                                           

10 EPA, Engineering and Economic Factors Affecting the 

Installation of Control Technologies for Multipollutant 

Strategies; EPA-600/R-02/073 October 2002.
schedules, with a few exceeding 48 months. EPA engineering 

staff have extensive experience with power plant and APC system 

design, construction, and operation. Based on that experience, 

EPA can observe that in the absence of a compelling deadline or 

major economic incentive, many large project schedules are 

considerably longer than necessary. Given further observations 

as explained below, EPA believes it is reasonable to expect that 

almost all future APC retrofits can be completed far more 

quickly than they were in recent history. 

EPA’s perspective on this matter derives in part from a 

comparison of longer APC schedules (as provided by some 

commenters) to the project schedule for an entire new coal-fired 

unit, including its APC systems. Springerville Unit 3, for 

example, is a new 400 MW subbituminous coal-fired unit with SCR 

and dry FGD that became operational in July 2006, some 33 months 

after the turnkey engineering-construction contractor was given 

a notice to proceed with engineering.11 Springerville was clearly 

on an accelerated schedule, as its original planned schedule was 

about 38 months. Another example is Dallman Unit 4, a highsulfur bituminous coal-fired 200 MW unit with SCR, fabric 

                                                           

11 Best Coal-fired Projects, Springerville Unit 3 Expansion 

Project, Power Engineering, November 2006, 

http://www.powergenworldwide.com/index/display/articledisplay/28

2547/articles/power-engineering/volume-111/issue1/features/projects-of-the-year.html 
filter, wet FGD, and wet ESP. Dallman Unit 4 was first 

synchronized in May 2009, several months ahead of schedule, and 

about 36 months after its turnkey contractor placed initial 

major equipment orders.12 The main point here is that recent APC 

project schedules, and those of large complex power projects, 

can be significantly accelerated. Because the scope and 

complexity of the work involved for an entire new coal unit and 

its APC systems is perhaps five times greater than that of a 

retrofit wet FGD system alone, EPA believes it is reasonable to 

expect that even the most complex retrofit APC project can be 

significantly accelerated as well. Additional factors are 

discussed below that further support the feasibility of 

installing by 2014 the 5.9 GW of FGD retrofits projected for 

this rule. 

Although IPM modeling provides reliable estimates on a 

regional basis, and cannot be as accurate at the level of 

individual plants or units, it is informative and relevant to 

consider IPM’s plant level projections in this case. Although 

the IPM-projected retrofits named below may not actually occur, 

IPM projects that they would be economic and would allow 

industry to meet the tighter SO2 emission standards in Group 1 

                                                           

12

http://www.cwlp.com/electric_division/generation/Dallman%204%20P

ower%20Plant%20of%20the%20Year.pdf
states in 2014. EPA notes that the owners of the particular 

plants mentioned below (Duke Energy, AEP, Edison International) 

are large, experienced, versatile utilities that have done 

considerable advance planning and should also have above-average 

flexibility to comply with state budgets across their fleets. 

EPA would expect such owners to have relatively little 

difficulty in permitting and financing FGD retrofits. 

Of the Transport Rule-related FGD retrofits, 0.2 GW is 

projected to use dry FGD, which EPA expects to be simpler and 

quicker to install than wet FGD. Half of the 5.9 GW 

(Muskingum, Rockport) has already been committed under consent 

decrees to add controls or retire;13 and EPA reasonably believes 

that significant preliminary project planning work has already 

been done for those projects. An additional 1,200 MW (Homer 

City) had completed project planning and was ready to proceed in 

2007, before putting the project on hold.14 The latter plant is 

now facing EPA legal action and the possibility of a required 

expeditious FGD retrofit.15 Thus, of the 5.9 GW of projected FGD 

                                                           

13http://www.epa.gov/compliance/resources/decrees/civil/caa/americ

anelectricpower-cd.pdf 

14http://www.businesswire.com/news/home/20060731005193/en/Contract

ors-Selected-Install-Emissions-Control-System-Pennsylvania 

15http://www.epa.gov/Compliance/resources/complaints/civil/caa/hom

ercity-cp.pdf
retrofits resulting from this rule, nearly 75 percent appears to 

be in good position for an early start of construction, and over 

3 GW of that would be bringing forward already committed 

compliance start dates. 

Any of the above mentioned potential retrofits or any other 

unit that might choose to retrofit FGD for a January 2014 

compliance date will likely have to use various methods to 

accelerate the project schedule. Such methods could include the 

use of parallel permitting, overtime and/or two-shift work 

schedules during construction, and 5- or 6-day work weeks 

instead of the 4-day x 10-hour schedules often used to minimize 

cost when time is not of the essence. Increased use of offsite 

modularization and pre-fabrication of APC components could also 

shorten schedules and reduce job hours. 

EPA believes that the January 1, 2014 compliance date is as 

expeditious as practicable for the sources installing large, 

complex control systems. The following additional observations 

support EPA’s expectation that the limited 5.9 GW of FGD 

retrofits can be realized in the 30 month interim between rule 

signature and the start of 2014: 

● There are documented instances of large, complex wet 

FGD retrofits being deployed in less than 30-months (excluding 
the time for owners’ project planning). Examples are Killen 

Station Unit 216, and Asheville Unit 1.17

● In 2009 the APC supply chain deployed more than six 

times more GW capacity of FGD and SCR controls than the 5.9 GW 

of FGD that would be deployed by 2014 under this Rule. 

● The APC supply chain has seen a 2-year decline in 

deployments since its peak in 2009, but in 2011 is nonetheless 

putting into service about three times more GW capacity of FGD 

and SCR controls than the 5.9 of FGD that would be deployed 

under this Rule. 

● Because the supply chain has been in decline, but 

remains quite active, there are now adequate supply chain 

resources available that can be quickly reengaged to support a 

rapid deployment of 5.9 GW of FGD. 

 EPA recognizes that the installation of any amount of 

scrubbers in this short time frame will require aggressive 

                                                           

16 Black & Veatch, 

http://www.bv.com/News_3_Publications/News_Releases/2005/0503.as

px (start), 

http://www.bv.com/wcm/press_release/07252007_9767.aspx

(completion) 

17 PowerGenWorldwide, Projects of the Year, January 1, 2007, 

http://www.powergenworldwide.com/index/display/articledisplay/28

2547/articles/power-engineering/volume-111/issue1/features/projects-of-the-year.html 
action by plant owners and that the owners who can meet this 

schedule will already have done their project planning and will 

be ready to place orders. An example of such “early movers” was 

seen in the power sector’s anticipation of CAIR. EPA data 

indicate that solely CAIR-driven FGD and SCR deployments of 

about 6 GW occurred within two and one-half years after CAIR’s 

finalization in mid-2005, showing that at least 20 percent of 

the total CAIR-only controls effort through a 2010 compliance 

date was sufficiently planned for installation to start before 

or immediately upon finalization of the rule. EPA reasonably 

expects that similar advance planning has already been done for 

units that would retrofit under this rule. 

In the event that a particular control installation 

requires additional time into 2014 to come online, EPA believes 

compliance would not be jeopardized given the ability of sources 

to purchase allowances during that time. This approach could be 

supported by some sources with FGD that have the ability to 

increase their SO2 removal above historic rates, perhaps through 

relatively low cost upgrades to improve scrubber effectiveness, 

or by operating scrubbers at higher chemistry ratios. The 

ability of sources to temporarily or permanently substitute dry 

DSI for FGD serves as another backstop for any feasibility 

issues regarding FGD. Note that the updated modeling for this 
rule projects the addition by 2014 of about 3 GW of DSI for SO2

control using trona or other sorbent. DSI is a relatively low 

capital cost technology that readily can be installed in the 

time frame available for compliance.18,19 

It should also be noted that most APC retrofits will 

involve a source outage for final “tie-in” of retrofitted 

systems to existing systems, during which time emissions from 

the affected units are zero. For some sources, the duration of 

this tie-in outage may effectively extend the deadline by which 

all of the projected emission reductions need to occur. 

Although EPA believes that installation of 5.9 GW of FGD at 

facilities by January 1, 2014 is feasible, EPA also conducted an 

IPM sensitivity analysis to examine a scenario in which FGD 

retrofitting by 2014 is not allowed. Results of EPA’s “no FGD 

build in 2014” analysis indicate that if the power industry were 

subjected to the requirements of this rule without an FGD 

retrofit option for compliance until after 2014, covered units 

would still be able to meet the Transport Rule requirements in 

                                                           

18 ICAC letter to Senator Carper, November 3, 2010, 

http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf

19 Assessment of Technology Options Available to Achieve 

Reductions of Hazardous Air Pollutants, URS Corporation, April 

5, 2011, 

http://www.supportcleanair.com/resources/studies/file/4-8-11-

URSTechnologyReport.pdf
every state while respecting each state’s assurance level. (See

the docket to this rulemaking for the IPM run titled "TR_No_FGD_ 

in2014_Scenario_Final.”)

In this scenario without the availability of new FGD by 

2014, sources in covered states complied with the Transport Rule 

budgets by using moderate additional amounts of DSI retrofits, 

switching to larger shares of sub-bituminous coal, and 

dispatching larger amounts of natural gas-fired generation in 

lieu of the FGD retrofits that are projected as being most 

economic under modeling of the Transport Rule remedy. Because 

new FGD capacity is included in EPA’s projection of the leastcost set of SO2 emission reductions required in Group 1 states, 

the “no FGD” sensitivity scenario did project higher system 

costs, although these costs were still substantially lower than 

the remedy EPA modeled in the Transport Rule proposal. 

The “no FGD” analysis indicates that while the ability of 

Group 1 states to meet their 2014 SO2 budgets is facilitated by 

FGD retrofits, they are by no means required, nor is Transport 

Rule compliance jeopardized by their absence. Even under a 

scenario in which sources fail to complete FGD retrofits by 

2014, sources in the affected states would have other compliance 

options available at reasonable cost to meet the state’s budget 

requirements. This analysis shows that Group 1 states would be 
able to comply with their 2014 SO2 budgets by relying on other 

emission reduction opportunities that do not require FGD 

retrofits. EPA analysis confirms that those alternatives are 

feasible both in terms of cost and timing. 

Finally, EPA recognizes that, when finalized later this 

year as currently scheduled, the Mercury and Air Toxics 

Standards (MATS) will require significant retrofit activity at 

covered sources in the power sector with a 2015 compliance date 

for that rule. EPA's projections of retrofit activity under the 

final Transport Rule are highly compatible with its projections 

of retrofit activity under the proposed MATS (which included the 

proposed Transport Rule in its baseline). EPA therefore 

anticipates that the Transport Rule's projected retrofit 

activity will not only be the least-cost compliance pathway to 

meeting state budgets in 2014 but will also accelerate emission 

reductions subsequently required by the effective date of MATS. 

The final Transport Rule's projected 2014 retrofit installations 

will also further incentivize the power sector to ramp up its 

retrofit installation capabilities to achieve broader deployment 

of the projected pollution control retrofits under the proposed 

MATS. 

Considering all the reasons given above, EPA has concluded 

that the 2014 requirements for SO2 emissions in the states 
covered by the Transport Rule are reasonable and can be met by 

the power industry by a variety of means. 

c. Coal Switching for SO2 Compliance in 2012 and 2014 

Coal switching is another mechanism which can be used along 

with operating pollution controls in 2012 for compliance. It 

will be a complementary activity by many coal-fired units 

alongside of operating pollution controls and the addition of 

more scrubbers and DSI in 2014. 

In the proposal, EPA noted that coal switching could serve 

as a compliance mechanism for 2012. EPA requested comment on 

the reasonableness of EPA’s assumption that coal switching will 

have relatively little cost or schedule impact on most units. 

EPA received substantial comment suggesting that the coal 

switching and coal blending projected by EPA modeling are not 

feasible for all units, and that, if feasible, would often incur 

a cost through the derating of the unit associated with the 

switch to a lower sulfur coal or coal blend. Additionally, 

sources indicated that coal switching by 2012 would not always 

be possible in the six month window between final rule signature 

and start of compliance. These feasibility concerns stemmed 

from restrictions included in existing coal supply contracts and 

from boiler design constraints that may hinder coal switching 

within a 6 month window. 
EPA agrees with these concerns and revised its IPM modeling 

to limit coal switching capability in 2012 for particular units 

that may have trouble switching coals or coal blends in a six 

month time frame. A cost adder was also included in the IPM 

modeling for coal switching to capture the potential cost burden 

of deratings that might accompany switching to a very low sulfur 

subbituminous coal or coal blend. 

A particular commenter concern regarding switching to lower 

sulfur within the eastern bituminous coals related to a possible 

impact on the performance of a cold-side electrostatic 

precipitator (ESP). Some ESPs that operate at acceptably high 

collection efficiency when using a high- or medium-sulfur 

bituminous coal may experience some loss in collection 

efficiency when a lower sulfur coal is used. Whether this 

occurs on a specific unit, and the extent to which it occurs, 

would depend on the design margins built into the existing ESP, 

the percentage change in coal sulfur content, and other factors. 

In any case, industry experience indicates that relatively 

inexpensive practices to maintain high ESP performance on lower 

sulfur bituminous coals are available and can be used 

successfully where necessary. These include a range of upgrades 
to ESP components and flue gas conditioning.20 EPA therefore 

assumes that it will not be necessary for units that switch from 

higher to lower sulfur bituminous to make a costly replacement 

of the ESP. 

Coal switching as a SO2 compliance option might also include 

switching from bituminous to subbituminous coal. EPA’s analysis 

does not assume that a unit designed for bituminous can switch 

to (very low sulfur) subbituminous coal unless the unit’s 

historical data demonstrate that capability in the past. EPA 

assumes that units with that demonstrated capability have 

already made any investments needed to handle a switch back to 

the use of subbituminous coal at a similar percentage of its 

heat input as in the past. For IPM analysis in the final rule 

EPA also introduced a coal switching option that assumes that 

units can increase a historically low percentage use of 

subbituminous to a “maximum” level, if economic. This option 

includes an appropriate derate in output, increase in heat rate, 

and additional capital and operating costs. Details of this and 

other IPM updates for this rule are provided in the IPM Modeling 

Documentation in the docket for this rulemaking (“Documentation 

                                                           

20 Assessment of Technology Options Available to Achieve 

Reductions of Hazardous Air Pollutants, URS Corporation, April 

5, 2011, 

http://www.supportcleanair.com/resources/studies/file/4-8-11-

URSTechnologyReport.pdf
Supplement for EPA Base Case v.4.10_FTransport – Updates for 

Final Transport Rule”). 

 Some commenters also expressed concern with the assumption 

that coal-switching from lignite to sub-bituminous is a costeffective or feasible emission reduction strategy, particularly 

at Texas EGUs. EPA carefully considered these comments and 

adjusted its modeling of cost-effective reductions to address 

this concern. Specifically, EPA made adjustment in the model so 

that it assumes coal-switching is not a compliance option at the 

specific units where commenters identified technical barriers to 

sub-bituminous coal consumption. The Transport Rule emissions 

budgets are based on this adjusted modeling which does not 

assume any infeasible coal-switching from lignite to subbituminous. In addition, EPA’s analysis of cost-effective 

reductions in each state presented in section VI.B shows that 

Texas is capable of cost-effectively meeting its Transport Rule 

emission budgets; however, EPA also conducted sensitivity 

analysis that shows Texas can also achieve the required costeffective emission reductions even while maintaining current 

levels of lignite consumption at affected EGUs. More details on 

this analysis can be found in the response to comments document 

in the docket for this rulemaking.