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 SO 2 budgets at the start of 2014. In 2012, the industry will largely meet the rule’s NO X 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 NO X pollution controls in states not previously subject to CAIR. For the SO 2 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 NO X and SO 2 reductions as well as account for reductions from additional advanced NO X and SO 2 controls that are driven by other state and federal requirements. In addition tothese reductions, companies in Group 1 states are also projected to add a limited amount of advanced SO 2 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 NO X and SO 2 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 Rule**  1

1 GW: gigawatts of capacity retrofitted; FGD: flue gas desulfurization (SO 2 control); DSI: dry sorbent injection (SO 2Capacity 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 PM 2.5 and ozone-season operation of NO X post-combustion controls in states covered for ozone. EPA also modeled emission reductions available in 2012 at the $500/ton threshold for SO 2, $500/ton for annual NO X , and $500/ton for ozone-season NO X .

control); SCR: selective catalytic reduction (NO X control); LNB/OFA: low-NO X burner and/or overfire air (NO X controls)For SO 2 , 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 PM 2.5 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 anadditional 39 GW of advanced SO 2 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 SO 2 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 SO 2 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 NO X 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 NO X 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-NO X burners and overfire air) are scheduled to come online in the region during the 2010-2012 timeframe, bringing the totalregion’s coal capacity operating with NO X 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 NO X control technology in place in 2010. EPA expects a significant portion of thatcapacity 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 NO X 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 NO X emission rates by enhancing performance of existing combustion controls or SNCR or by fuel switching.

For NO X , EPA has also concluded that it is appropriate to require reductions through a limited amount of combustioncontrol improvements, and in some cases, retrofits such as lowFormatted: SubscriptNO X 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 NO X control such as SCR. Assumed improvements and retrofits for the January 1, 2012 deadline for annual NO X reductions therefore only involve the much simpler LNB/OFA control modifications or installations. Alternatively, some plant owners might choose to achieve NO X 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 NO X 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.pdfBased 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 NO X caps. EPA reflects the effects of these installations in the 2012 annual and ozone-season NO X budgets, which would yield reductions of approximately 28,000 tons of annual NO X and 14,000 tons of ozone-season NO X . 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 NO X 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 NO X 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 NO X (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 NO X 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-NO X 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 NO X 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 NO X System at Limestone Unit 2 Cuts Texas Lignite, PRB and Pet Coke NO X , http://www.fwc.com/publications/tech_papers/files/tp_firsys_01_0 2.pdf

5 B. Courtemanche, et al, Reducing NO X Emissions and Commissioning Time on Southern Company Coal Fired Boilers With Low NO X 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 NO X 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 NO X budgets, and no more than 11 percent of any affected state’s annual NO X budget. Under such a scenario, these delayed reductions would still be well within the 18 percent variability limit applied to each state’s annual NO X budget. In light of this limitedconsequence and the supporting material above, EPA includes LNBdriven NO X reductions in both annual and ozone-season NO X 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**  **NO X**  **Program***

NO X Reductions from LNB Operation from January - April (tons) Annual NO X S tate 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- w**  **ide 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 NO X 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 NO X 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 SO 2 requirements, EPA projects that the power industry will rely on existing controls, operate newly installed advanced controls necessary for other bindingstate 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 SO 2 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 SO 2 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 wasabout 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/282547/articles/power-engineering/volume-111/issue1/features/projects-of-the-year.htmlfilter, 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 SO 2 emission standards in Group 1

12 http://www.cwlp.com/electric_division/generation/Dallman%204%20P ower%20Plant%20of%20the%20Year.pdfstates 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

13 **http :**  //www.epa.gov/compliance/resources/decrees/civil/caa/americ anelectricpower-cd.pdf

14 http://www.businesswire.com/news/home/20060731005193/en/Contract ors-Selected-Install-Emissions-Control-System-Pennsylvania

15 http://www.epa.gov/Compliance/resources/complaints/civil/caa/hom ercity-cp.pdfretrofits 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 (excludingthe time for owners’ project planning). Examples are Killen Station Unit 2 16 , 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/282547/articles/power-engineering/volume-111/issue1/features/projects-of-the-year.htmlaction 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 SO 2 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 thisrule projects the addition by 2014 of about 3 GW of DSI for SO 2 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.pdfevery 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. Becausenew FGD capacity is included in EPA’s projection of the leastcost set of SO 2 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 SO 2 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 beable to comply with their 2014 SO 2 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 SO 2 emissions in the statescovered by the Transport Rule are reasonable and can be met by the power industry by a variety of means.
c. Coal Switching for SO 2 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 upgradesto 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 SO 2 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.pdfSupplement for EPA Base Case v.4.10_FTransport – Updates for Final Transport Rule”).
Some commenters also expressed concern with the assumptionthat 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 notassume 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 sensitivityanalysis 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.