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Docket Number EPA–HQ–OAR–2009–0491

Response to Comments on the Proposed Transport Rule: Federal 

Implementation Plans To Reduce Interstate Transport of Fine 

Particulate Matter and Ozone

(75 FR 45210; August 2, 2010)

Transport Rule

Engineering Feasibility

Response to Comments

U.S. Environmental Protection Agency

Office of Air and Radiation

July 2011
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Contents

Introduction................................................................................................................................. 3

Implementation Issues ................................................................................................................ 4

Emission Control Capabilities.................................................................................................. 13

Implementation Costs............................................................................................................... 14

Switching from Lignite to Subbituminous................................................................................ 15
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Introduction

This document responds to comments on the proposed Transport Rule and supplements the 

Transport Rule Primary Response to Comments (available in the docket). This document 

provides responses to significant public comments on engineering feasibility as received in 

response to the United States Environmental Protection Agency’s Notice of Proposed 

Rulemaking (NPR): Federal Implementation Plans to Reduce Interstate Transport of Fine 

Particulate Matter and Ozone (Interstate Air Quality Rule), issued August 2, 2010. 

An extensive general discussion of engineering feasibility is provided in preamble section 

VII.C.2, Compliance and Deployment of Pollution Control Technologies. It addresses many of 

the major aspects of the engineering feasibility of implementing the flexible range of technical 

options available for compliance with the Transport Rule by its compliance deadlines of January

1, 2012 and January 1, 2014. This document provides responses to additional engineering 

feasibility concerns that were repeated by multiple commenters. 

The full text of all comments to which these responses apply are included in the Transport Rule 

Primary Response to Comments, section V.C.2, Reductions as Expeditiously as 

Practicable/Feasibility of the 2012 and 2014 Compliance Deadlines (available in the docket). 

Certain related comments, including those supporting the rule’s engineering feasibility, are 

separately addressed in the Transport Rule Primary Response to Comments, section V.C.2.

Responses provided in this document are organized under the following major subject headings, 

each representing broad general areas of concern to multiple commenters:

 Implementation Issues 

 Emission Control Capabilities

 Implementation Costs 

 Switching from Lignite to Subbituminous

Responses are presented as individual paragraphs under these headings, addressing more specific 

areas of concern as identified by each paragraph subheading.
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Implementation Issues

Request to Defer Implementation for Compliance

After careful consideration of public comments and the evidence on record for EGU 

emission reduction feasibility, EPA did not find a reasonable technical basis for altering the 

Transport Rule compliance deadlines of 2012 and 2014 as originally proposed. See preamble 

section VII.C regarding EPA’s rationale for the compliance schedule. 

Owner’s Decisions & Options

As part of the court’s remand, the CAIR programs have remained in place temporarily until 

superseded by EPA’s promulgation of the Transport Rule. While some utilities opted to 

temporarily slow, delay or suspend retrofit activities in the wake of the court’s judgment and 

pending the promulgation of the replacement rule, these actions do not constitute a sufficient 

basis for determining that such sources are incapable of meeting the replacement rule’s 

compliance dates. The owner is ultimately responsible for assuring adequate and timely

performance of a retrofit installation by utilizing competitive supplier selection to award a 

contract. Moreover, the Transport Rule is inherently flexible – it allows unit owners multiple 

options to attain compliance deadlines; namely, unit owners may choose to maximize 

performance of existing pollution controls, shift power generation to cleaner units, expedite 

retrofit work where necessary (utilize multi-shift schedule or extended overtime), increase 

use of cleaner fuels, and/or purchase allowances to cover emissions.

Conflicts with a Utility’s Long Term Plans

The EPA believes promulgation of the final Transport Rule provides important regulatory

certainty which will allow utilities to improve planning efforts and, if necessary, amend longrange strategic plans as they have successfully done in response to past regulations. EPA is 

not responsible for aligning its regulatory actions (which are authorized by statute) to any

corporation’s pre-existing planning, whether or not such planning accurately anticipates 

specific regulations. EPA conducts a notice-and-comment rulemaking period giving the 

public and affected entities advanced notice of pending regulations. The opportunity for 

input before finalization allows additional time for affected sources to adjust their long-range 

planning accordingly.

Municipality Impacts and Challenges

EPA analyzed and considered the impacts of the Transport Rule on municipal EGUs. For a 

discussion on the rule's impact regarding municipalities, see RIA chapter 9.

Complete Detailed Engineering Required for Initiating Work 

Complete detailed engineering is not required for making an award; rather, an award requires 

conceptual engineering to size major equipment, determine process flows, identify scope, 

establish permit requirements, and estimate total installed cost. At its conclusion, order 

placement for long lead items and permit submission can occur. Detailed engineering is 

required for construction and installation activities.
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The Transport Rule generally sustains an already-present economic incentive for pollution 

control retrofit planning originally imposed by the Clean Air Interstate Rule. Many retrofit 

planning activities launched under CAIR, including fleet assessment, conceptual studies, cost 

estimates, process flows, material balances, drafting permit applications, and aligning prime 

contractors and sub-contractors, should have been completed and retained by many utilities. 

Some utilities may have decided to temporarily postpone further deployment in response to 

the remand of CAIR (for example, Clifty Creek and Kyger Creek,

1

but upon promulgation of 

the Transport Rule, work can resume efficiently with installation. As a result, the EPA 

anticipates that units originally affected under CAIR are in a position to issue contract awards

efficiently and in a timely manner for desired retrofits to make emission reductions under the

Transport Rule programs. 

Negotiating Contracts, Competitive Bid Evaluation – More Time Required for Compliance

EPA believes that in response to CAIR and subsequently to the proposed Transport Rule, 

utilities were well positioned to solicit and evaluate retrofit project bids as part of their 

advance planning efforts that have been visibly underway from many companies. This 

preparation would allow efficient decisions to award contracts upon final Transport Rule 

promulgation, consistent with the compliance deadlines which industry has been able to 

anticipate since the Transport Rule’s original proposal. As EPA explained in the proposed 

Transport Rule, the Court’s remand of CAIR in 2008 explicitly rejected that rule’s 2015 

deadline as failing to respect Clean Air Act attainment deadlines for downwind areas, and 

that a replacement rule would need to respect these attainment deadlines. As a consequence 

of the Court’s ruling on CAIR, EPA believes any reasonable observer could have anticipated 

as early as 2008 that EPA’s replacement rule would need to consider necessary emission 

reductions prior to 2015; therefore, it is reasonable for EPA to expect that utilities would 

have commenced advanced planning efforts for potential cost-effective retrofits, including 

contract negotiations and bid evaluations, in advance of final promulgation of the Transport 

Rule.

Financing / Investment Difficulties

EPA has not observed financing obstacles for pollution control retrofits under its previous 

trading programs. The EPA includes publicly-reviewed financial assumptions regarding 

pollution control investments in its IPM modeling of the power sector which indicates that 

the projected retrofits are economically viable in response to the final Transport Rule’s state 

budgets. The Transport Rule’s market-based trading programs create “bankable” value in 

each ton of emission reductions, thereby supporting financing in pollution control retrofits. 

Furthermore, the financial industry views utilities with large customer bases as less risky to 

finance due to the consistent, ample revenue stream. As noted in section VII.C.2 of the 

preamble, the projected cost-effective retrofits under the Transport Rule all occur at capacity

owned by such large utilities. To reduce financing risk, utilities have the option to award 

 

1

http://www.ovec.com/annrpt2009signed.pdf and 

http://www.ovec.com/News%20Release%20Clifty%20Creek%20Scrubbers%2012-15-10.pdf
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“fixed price” contracts. Considering the past successes of the pollution control industry

regarding retrofits, EPA believes the financial markets will supply adequate capital for units 

pursuing retrofits under the final Transport Rule. 

Permit Approval, PUC Approval, Existing Permits - Time Issues

EPA acknowledges that the time required for air permit approval varies from state to state. 

Many states established programs to aid the utility sector in complying with regulations. For 

instance, Indiana allows application for “Interim Approval” to commence construction,

2

Pennsylvania allows expedited review,

3

and Michigan, by policy, attempts to complete

permit to install (PTI) within 6 months4and usually takes less than 60 days.

5

States 

implementing “lean” permitting principles6achieved significant reductions in permit 

processing times. Three of four states (MI, ID, IN) typically process the permit in under 150 

days; the fourth state (IA) does it in 180 days. Moreover, the agency plans to issue guidance 

for permitting authorities and thereby reduce burdens and shorten time requirements. For a 

more detailed discussion, see Preamble section VII.I.1. 

NSR permitting is discussed in Preamble section VII.I.2. 

State pre-construction permitting requirements depend upon each individual state. 

Deregulated states (IL, NJ, NY, OH, PA) and regulated states (AL, CO, FL, GA, MN, MO, 

NC, VA) do not require pre-construction permits while some other states (IN, KY, MD, WI) 

require PUC (public utility commission) approval. For states obtaining PUC pre-approval 

for cost recovery, authorization typically averages 6 months and is obtained usually within 

one.

7

 Furthermore, while PUC approval is necessary to recover investment costs through 

rate payers, it is not a prerequisite for obtaining credit or performing conceptual studies. 

A covered unit’s existing permit limitations do not exempt the utility from Transport Rule 

compliance; rather, if permit revision is deemed necessary, the owner is expected to amend 

the permit and seek regulatory approval for the revision. During CAIR implementation, 

utilities obtained state commission approval and financing; therefore, EPA believes the 

Transport Rule’s requirements, with respect to the level and timing of reductions, are 

reasonable and consistent with the direction and timing of prior rulemakings and legal 

settlements, as evidenced by EPA’s projections showing that the majority of the most likely

units to consider cost-effective retrofits under the Transport Rule either conducted retrofit 

planning or even partial construction efforts previously or are already under an existing 

 

2

http://www.in.gov/idem/4830.htm

3

http://www.dep.state.pa.us/dep/deputate/airwaste/aq/permits/plan.htm

4

http://www.deq.state.mi.us/aps/downloads/permits/miparp/Brochure-New%20Permit%20Process.pdf

5

http://www.deq.state.mi.us/aps/downloads/permits/permits%20stats.pdf

6

http://www.epa.gov/lean/government/airpermitting/introduction.htm

7

“Public Utility Commission Report” March 31, 2011 by M.J. Bradley & Assoc LLC; web site: 

http://www.epa.gov/ttn/atw/utility/puc_study_march2011.pdf
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consent decree to install such retrofits in the future (see preamble section VII.C.2 for more 

information). 

Project Execution Issues Necessitate Long Time Periods

Numerous commenters claimed that actual project execution timeframes exceeded the time 

allotted by the proposed rule. To illustrate the point, commenters referenced specific retrofit 

project elements with asserted time requirements for their completion as part of the 

retrofitting process. EPA recognizes that retrofitting EGUs with pollution control technology

requires a substantial amount of labor hours from a multitude of skill sets. However, EPA’s

schedule length assumptions for SO2 post-combustion projects relevant to this rulemaking 

are fully compatible with total labor hours required for completion. Project schedule length is 

heavily influenced by resource dedication and execution method. While any project can be 

executed at a slow pace, the EGU pollution controls industry developed into a mature 

industry in response to the Acid Rain Program, the NOX SIP Call, and CAIR with the ability

to perform accelerated project execution using a faster and more efficient Design-Build8

process. The power sector has recognized considerable efficiency gains through integrating 

standardized equipment designs, systems approach, and modular construction techniques9as 

well as the formation of business alliances10 to reduce frictional time lags.

A typical control retrofit project consists of the following elements, several of which may

occur simultaneously: site studies, conceptual engineering, equipment sizing, cost 

estimating, planning, detailed design, procurement, construction, commissioning / testing,

and permit application. For design-build methodology, the project is divided into two major 

phases: pre-award work requiring minor expenditures (site studies, conceptual engineering,

equipment sizing, cost estimates, schedule planning) and award work requiring significant 

capital commitment (detailed design, procurement, construction, commissioning / testing). 

Pre-award work elements are typically executed sequentially since each preceding stage’s 

results inform the following stage; however, award work elements can be executed with 

“Lean Construction” techniques11 to shorten time frames. Since a typical emission control 

device is a combination of smaller independent sub-systems, the design / build process with 

“lean construction” is highly suited for retrofits. For instance, a wet FGD’s chimney, 

scrubber, landfill, reagent preparation, rail car unloading, waste water treatment, and 

dewatering facility occupy different plant site locations; thereby, allowing simultaneous 

design, procurement, construction, and testing activities. To illustrate the point, Asheville 

Power station FGD retrofit was completed on a 26 month schedule,

12 and an AEP unit in 

 

8

http://www.dbia.org/about/designbuild/

9

http://www.babcock.com/library/pdf/E1013167.pdf

10 http://www.powermag.com/issues/cover_stories/City-of-Springfields-CWLP-Dallman-4-Earns-POWERsHighest-Honor_2060_p5.html).

11 http://www.powermag.com/coal/Lean-Construction-Principles-Eliminate-Waste_2886.html

12 http://www.coalpowermag.com/plant_design/Case-Histories-Asheville-Power-Stations-Retrofit-First-to-MeetNorth-Carolinas-Clean-Smokestacks-Act_63.html
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Brilliant, Ohio required only 18 months to complete construction on a wet FGD retrofit.

13

 

(For additional retrofit examples, see preamble section VII.C.2)

EPA does not agree with commenters that lengthy retrofit schedules from various individual 

prior projects are dispositive of the power sector’s ability to install cost-effective retrofits 

under the Transport Rule’s schedule. In particular, such examples cited by commenters fail 

to account for the adoption of proven faster execution methods evidenced by numerous units

that have demonstrated FGD retrofit project completion in less than 30 months. In particular, 

commenters who cite examples of lengthy or delayed retrofit schedules from projects 

conducted during the highly uncertain period of the CAIR remand (when it was prudent to 

proceed cautiously) cannot reasonably expect such experiences to apply to retrofit project 

execution with the benefit of renewed regulatory certainty gained by promulgation of the 

final Transport Rule (when it is prudent to proceed expeditiously and with confidence).

Claims of Infeasibility for 2014 Compliance

While the timeframe imposed by the final rule is ambitious, EPA believes it can be met. A 

project’s completion time is a function of an owner’s decisions; examples of long completion 

timeframes offer more of a window into project management preferences rather than

minimum time requirements to complete the retrofit project expeditiously. The utility can 

encourage faster project completion by stipulating penalties during contract negotiation for 

failing to achieve commercially available dates. EPA believes completion of these retrofit 

projects is feasible by 2014 based on several previous retrofit projects that were successfully

deployed within the timeframe allowed. In fact, the wet FGD at Homer City unit 3 was 

placed in service 29 months after project award.

14

 With the massive build-out over the past 

decade for CAIR, the engineering, procurement, and construction sector for controls 

equipment developed into a mature industry with many suppliers and options to select.

15

 As 

observed during implementation of CAIR, significant deployments were achieved in 

response to the NOX SIP Call which yielded notable efficiencies in retrofit deployments, 

allowing for shorter project completion timelines.

16

 Given the considerable experience and 

skills obtained by the power sector and the pollution control suppliers during this time 

period, EPA believes that the Transport Rule offers an acceptable deployment schedule for 

the projected retrofit installations in the least-cost compliance pathway modeled for the final 

Transport Rule. (For more discussion, see preamble section VII.C.2). As described in that 

section, EPA analyzed the scenario in which FGD retrofitting in 2014 is not feasible (an 

assumption that EPA does not agree with) but where sources are still required to comply with 

 

13 http://www.graycor.com/projects/fgd-retrofit/493

14 Alstom Flue Gas Desulfurization Technologies 2003; 

http://www.netl.doe.gov/publications/proceedings/03/NOxSO2/06-

Klitzke%20Sidwell%20Jensen%20presentation%20Part%20123.pdf

15 NESCAUM report “Control Technologies to Reduce Conventional Hazardous Air Pollutants from Coal-Fired 

Power Plants” by Andover Technology Partners, March 31, 2011

16 ICAC letter to Senator Thomas Carper, U.S. Senate, Nov 3, 2010; web site: 

http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf
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Transport Rule emission budgets. The results indicate that covered units would still be able 

to meet Transport Rule requirements in 2014, without any new FGD retrofits, while 

respecting each state’s assurance levels.17

Claims of Infeasibility for 2012 Compliance

The Jan 1, 2012 reductions projected by IPM are based on: 1) operating existing installed 

controls; 2) completing installation of previously announced control retrofits coming online 

by 2012; 3) Fuel switching / blending; and 4) installing combustion controls such as low 

NOX burners, overfire air or a combination thereof. EPA believes that these reduction 

strategies are feasible by the start of the Transport Rule programs in 2012; for more 

discussion, see preamble section VII.C.2.

Inadequate Labor Pool, Low Skill Level & Insufficient Equipment Suppliers

With current unemployment rates18, sufficient quantities of engineers and skilled craft19 exist 

for Transport Rule implementation. Likewise, for the extreme case of local labor shortages 

(which is not anticipated), this challenge can be overcome by instituting a workforce 

development20 action plan during project execution. This sector’s equipment suppliers and 

manufacturers are underutilized21 since 2010.

Long Lead Times for Key Components

Multiple public commenters express concern with the delivery of equipment in time to meet 

compliance dates. In particular, UARG provided a table showing the increase in order lead 

time for ball mills, rubber lined pumps, air compressors, and internal recycle alloy spray

headers due to heavy construction activity between 2003 and 2006. This table can be 

reviewed in its original context in Coal Power’s publication; “Plant Economics – The Impact 

of Shortages on FGD Prices” Table #1, by Steve Katzberger, Sept 1, 2007.

22

 This comment 

selectively focuses on this table to claim that there is insufficient time available for 

equipment delivery to comply with the rule. However, earlier in that article, a bar chart 

illustrates year-by-year announced FGD start-ups from 2006 through 2015 for CAIR 

compliance. Clearly, the long lead times tabulated for Dec 2006 reflect the more than 80 

FGD systems expected to be in-service for 2008 and 2009. EPA’s projections of least-cost 

compliance with the Transport Rule’s state budgets include only 5.7 GW of wet FGD 

retrofits by 2014; if we put that level of effort into the context of the historical data presented 

by the article’s graph on lead times, the projected FGD deployment for the Transport Rule is 

similar to the article’s 2006 FGD in-service projections, which required a 1 year lead time for 

 

17 EPA performed two variations of this analysis. The first is discussed in section VII.C. The second analysis 

applies the same constraint barring FGD retrofit 2014, but does so to the final remedy sensitivity that reflects the 

final variability limits. This analysis is titled “TR_Remedy_Sensitivity_final_variability_limits_no2014_FGD” and 

is available in the Transport Rule docket. Both analyses reached the same conclusion that is described above. 

18 http://www.bls.gov/news.release/empsit.t14.htm

19 http://www.supportcleanair.com/resources/letters/file/11-11-10-AFL-Letter-To-Sen-Carper.pdf

20 http://hamon-researchcottrell.com/news_20100601

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

22 http://www.coalpowermag.com/plant_design/Plant-Economics-The-Impact-of-Shortages-on-FGD-Prices_73.html
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equipment (Table 1, column Oct 2005). Furthermore, the longest lead time item (rubber 

lined recycle pumps) within Katzenberger’s article required 112 weeks for delivery; the final 

Transport Rule is being promulgated 30 months (or 130 weeks) ahead of the start of the 2014 

control period – this still allows 18 weeks (even under Katzberger’s lead times) to install, 

test, and commission the pumps. In addition, the commenter does not cite any estimates of 

current lead times for equipment affecting retrofit deployment; rather, the commenter asserts 

future infeasibility by relying on outdated information which EPA believes does not 

accurately characterize the current state of the market or the opportunities for efficient and 

expeditious retrofit deployment discussed above and in section VII.C.2 of the final Transport 

Rule preamble. 

Multi-unit Stations – More Time Required

EPA acknowledges that some of the plants that choose to retrofit with FGD control systems 

may wish to retrofit more than one unit on the plant site at the same time. EPA expects that in 

many cases it will be possible and economic to combine emissions from several units into a 

larger control device. In such combined multi-unit cases the installation time should be only

slightly greater than for a single unit, and still feasible for compliance by 2014. In any event, 

a multi-unit retrofit on one site has significant execution cost and schedule advantages not 

realized at multiple single unit stations through aggregating resources to create economies of 

scale. These include one-time mobilization, extended equipment rental, dedicated staging 

area, efficient skilled craft utilization, and reduced administrative outlays. Furthermore, units 

can be “tied-in” sequentially, avoiding a complete station shutdown during installation. 

Successful examples include Dickerson Station’s three 190 MW units feed a single scrubber 

which discharges into a single flue stack. Chalk Point station’s two units share a single 

common wet FGD.23 FirstEnergy’s Sammis station’s wet scrubber project combined 

emissions from seven units into three absorbers while AEP’s Clifty Creek24 and Kyger 

Creek25 stations will employ similar design concepts for their wet FGDs. 

Commissioning / Start-up - Time Requirements

Commissioning equipment is an essential part of project completion. EPA acknowledges the 

time required for testing pollution control systems may span weeks or months. Individual 

components can be inspected and pre-tested during construction activities to determine faulty

equipment. Commissioning involves testing and fine tuning the entire system while firing 

fuel. Therefore, the pollution controls equipment is fully functional and removing pollution. 

Consequently, emissions are reduced during the commissioning phase. The Transport Rule 

does not impose any specific “deadline” on units to finish commissioning a retrofit that the 

owners select as a cost-effective reduction strategy under a state’s emissions budgets. In fact, 

as the retrofitting units are taken offline for final tie-in and are subsequently tested with the 

new pollution control equipment, their emissions are likely to decrease substantially, which is 

 

23 http://www.powermag.com/coal/Top-Plant-Dickerson-Generating-Station-Dickerson-Maryland_3027_p2.html

24 http://www.ovec.com/News%20Release%205-11-06%20IKEC.pdf

25 http://www.ovec.com/News%20Release%205-11-06%20OVEC.pdf
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fully compatible with the start of the Transport Rule programs, when each ton emitted would 

require the utility to submit an allowance (which has market value). Therefore, if a unit 

requires additional time leading into the beginning of 2014 to complete these final, low- or 

no-emitting phases of the retrofitting activity, that unit would potentially have even lower 

emissions in 2014 than it would have had it completed the retrofit on schedule. EPA does 

not believe, therefore, that commissioning or start-up time scheduling pose a material 

concern to Transport Rule compliance.

ESP Upgrades Required for Fuel Switching

Several commenters indicated fuel switching may require electrostatic precipitator (ESP) 

upgrades. Not all ESP’s require improvements due to fuel switching / blending since: 1) an 

existing ESP may have sufficient design / operating margins to accommodate increased 

particulate loading, and 2) the presence of a wet FGD augments PM control equipment by

effectively removing particulate matter itself. For those cases requiring upgrade, numerous 

ESP suppliers and after market businesses exist to perform upgrades. EPA does not believe, 

therefore, that an ESP upgrade is a necessary step for all units considering emission 

reductions from fuel switching under the Transport Rule, and where it may be necessary, 

EPA believes such units can readily upgrade their ESPs while making cost-effective emission 

reductions in response to the Transport Rule state budgets. For example, AEP’s Amos Power 

Plant refurbished an ESP within six months.26 

FRP pipe – Insufficient Specialized Skilled Craft for Installation

Commenters identified concerns about insufficient quantities of special skilled labor for 

installing and erecting fiberglass resin pipe (FRP) pipe. Most FRP pipe manufacturers offer 

installation training at the construction site or at the supplier’s premises, such as Ward 

Piping.

27

Fuel / Coal Switching or Blending Issues

Multiple commenters were concerned about difficulties involving fuel switching. EPA 

models fuel switching as either a complete fuel change or blending an existing fuel stock 

with a lower sulfur source. Blending is acceptable for compliance and complete fuel 

switching with associated plant modifications may be unnecessary. EPA carefully 

considered the feasibility of coal switching when analyzing the availability of cost-effective 

reductions in each state in 2012 and 2014. For more information, on fuel switching / 

blending, see preamble section VII.C.2.c. For IPM modeling basis regarding fuel switching / 

blending, see “Documentation Supplement for EPA Base Case v.4.10_FTransport – Updates 

for Final Transport Rule” contained in the docket.

Landfills - Construction Time Requirements

The compliance deadline allows sufficient time for completing landfills for FGD solids 

disposal. For example, DP&L will construct a landfill within 18 months to accept wastes 

 

26 http://ir.shawgrp.com/phoenix.zhtml?c=61066&p=irol-newsArticle&ID=1169687&highlight

27 http://www.wardfrp.com/wardabout.shtml
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generated from Stuart and Killen stations scrubbers.

28

 EPA notes, however, that retrofitting 

units do not necessarily need to complete landfill construction ahead of commencing 

operation of the retrofit to achieve cost-effective emission reductions under the Transport 

Rule programs. Such a source may either utilize a completed portion of the newly permitted 

landfill under construction, transfer waste off-site to a permitted landfill within the owner’s 

fleet, or contract waste removal (and disposal) services. For example, Dallman station 

subcontracts coal ash disposal at local abandoned mine.

29

 EPA uses a disposal cost 

assumption of $30-$50 per ton for wet FGD, dry FGD, and DSI controls, which EPA 

developed in consultation with an experienced power sector engineering firm.

Low NOX Burners - Installation Time Requirements

According to ICAC, low NOX burner installation requires between 6-8 months.

30

 With 

extensive low NOX burners retrofitted across the coal-fired EGU industry during the past 

three decades, EPA considers this a mature technology which can be economically and 

reliably installed within the allotted timeframe for compliance. See preamble section 

VII.C.2. 

SNCR - Installation Time Requirements

SNCR retrofit can typically be completed within 8 months.

31

 Due to its simplicity and 

extensive installations, EPA considers this a mature technology which can be economically

and reliably installed within the allotted timeframe for compliance. See preamble section 

VII.C.2. 

Stack / Chimney - Construction Time Requirements

EPA acknowledges that a wet FGD requires a “wet” stack which typically incorporates a 

fiberglass resin pipe (FRP) liner. The commenter’s claim that chimney engineering and 

construction require more than 30 months is inaccurate. Chimney size is determined by the 

scrubber’s location and discharge flow conditions, which the utility determines early on in 

the retrofit planning process and conceptual engineering design. Chimney construction can 

utilize the “slip form” method to reduce erection time, with assembly typically requiring less 

than 60 days. For instance, the Fayette power station stack #4 was poured within 39 days

32

and Kiewit Power construction teams poured the Sandy Creek Energy Station chimney

(height: 360 feet) in less than 30 days.

33 Dallman’s 440 ft unit #4 chimney required 28 days 

for erection.

34

 Thus, chimney engineering and construction are easily subsumed in the 

overall FGD deployment process that itself can be completed in less than 30 months.

 

28 http://www.peoplesdefender.com/main.asp?SubSectionID=83&ArticleID=131171&SectionID=13

29 http://www.cwlp.com/electric_division/generation/Dallman%204%20Power%20Plant%20of%20the%20Year.pdf

30 Institute of Clean Air Companies “Typical Installation Timelines for NOX Emissions Control Technologies...” 

Dec 4, 2006

31 Ibid.

32 http://www.lcra.org/newsstory/2008/scrubber_11071.html

33 http://www.kiewit.com/districts/kiewit-power/projects/Project.aspx?pid={EE7658FA-F440-440E-95C1-

E71C679A4682

34 http://www.cwlp.com/electric_division/generation/Dallman_4.htm
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CAIR Suffices... Transport Rule Not Required

The court in North Carolina identified several fatal flaws with CAIR, and remanded the rule 

so that EPA could develop a replacement consistent with the court’s opinion. Please see 

Preamble section IV.B and V.B for a more thorough discussion.

Emission Control Capabilities 

SCR Capability

The Transport Rule’s SCR NOX removal rates are consistent with commercially available 

equipment from multiple manufacturers. In fact, current technology is capable of removing 

up to 90% of incoming NOX (subject a floor limit of 0.06 lbm NOX / MMBtu) on a 

continuous basis. The utility is responsible for ensuring that the system design accounts for 

all factors leading to degraded performance over the expected life of the SCR system. 

EPA does not see any technical basis for claims that units originally designed for partial year 

operation would experience NOX removal difficulties under all-year operation. 

Properly operated and maintained SCR’s are capable of meeting their continuous design 

rating basis for NOX reduction (subject to floor limitations).

SNCR Capability

EPA examined the performance of existing SNCR at coal fired boilers covered by the 

Transport Rule. The units analyzed consisted of circulating fluidized bed, tangential fired, 

dry bottom wall fired, cell burners, cyclone burners, dry bottom vertically fired, dry bottom 

turbo fired, and stoker fired boilers. EPA considered hourly electronic emissions data as 

reported to the Clean Air Markets Division and assumed that SNCR operation occurred only

during the ozone season. By comparing the heat input-weighted average NOX emission rates

between the ozone season and non-ozone season for calendar years 2000-2010, the analysis35

determined that overall SNCR removal efficiency averaged 35.6% (within an observed range

of 15-78%). Based on this analysis, the EPA concludes that its SNCR removal efficiency

assumptions represent real-world SNCR performance and are appropriate for Transport Rule 

promulgation.

 

35 SNCR Operating Units – US EPA Data Analysis for Transport Rule RTC; see docket
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WFGD Capability

Current original equipment manufacturers (OEM) commercially offer (and advertise) wet 

FGD technology that is capable of removing 98% of SO2.

36

 For older wet FGDs, two options 

exist for enhancing performance: utilizing dibasic acid and / or upgrading internal

components. Other commenters observed that EPA’s dry and wet FGD removal rate

assumptions in the proposal’s power sector modeling reflected guaranteed performance

levels (which depend upon particular fuels and operating loads, among other factors), while

continuous in-service removal rates are typically lower, as the “guaranteed performance” 

level is not easily sustained in normal operations. In response to this comment, EPA 

decreased its removal rate assumptions for modeling emission reductions from dry and wet 

FGD retrofits. For more discussion, see “Documentation Supplement for EPA Base Case 

v.4.10_FTransport – Updates for Final Transport Rule,” in the docket for this rulemaking. . 

Implementation Costs

Breaking Contracts – Existing Fuel Purchasing Agreements

Numerous commenters argued that the EPA failed to examine the financial implications for 

early termination of existing fuel contracts – so called “breach” of contract penalties - to 

achieve emission reductions through fuel switching. EPA does not believe it is necessary for 

units to break existing fuel contracts for several reasons. First, the utility sector purchases 

20% of its fuel from spot markets,

37 and 97% of new fuel contracts are short term (less than 5 

yrs).

38 Also, the electric power sector manages fuel contracts through a tiered (or layered) 

structure that does not lock in the total fuel portfolio at a given unit for long periods of time 

(as various portions of that portfolio come up for contract renewal at frequent intervals). 

Utilities therefore have a large degree of existing flexibility in year-to-year fuel selection 

decisions even under existing contracts. Secondly, units have the flexibility to determine 

what proportion of fuel blending is economic in response to the Transport Rule’s state 

emission budgets, which does not prescribe a specific degree of fuel switching at any specific 

unit. In addition, the Transport Rule’s program structure offers the flexibility to purchase 

allowances as an interim measure if a utility desires extra time to negotiate a transition to 

new fuel contracts. 

Fiduciary Obligations Prevent Expenditures until Rule Finalized

Multiple commenters claimed that making major capital expenses prior to the rule’s 

promulgation would violate a public company’s fiduciary obligations. In all cases, the 

commenters failed to quantify the alleged financial burdens that they would incur to be 

positioned for expeditious compliance upon final promulgation. EPA recognizes that unit 

owners must consider regulatory risk associated with making major investments in control 

 

36 http://www.babcock.com/library/pdf/E1013167.pdf

37 EIA Quarterly Coal Report Oct-Dec 2010”; http://www.eia.gov/cneaf/coal/quarterly/qcr_sum.pdf

38 EIA “Coal Transportation: Rates and Trends”; http://www.eia.gov/cneaf/coal/page/trans/ratesntrends.html
Page 15 of 19

equipment; however, the expenditures for determining potential retrofit requirements (preaward work) are minimal, with conceptual engineering studies accounting for less than 1% of 

total installed cost. For example, Nebraska Public Power District (NPPD) commissioned a 

$2.4 million study to develop a “ready to issue” contract for an FGD retrofit estimated to cost 

$1 billion for the 1,365 MW Gerald Gentleman Station.39 This represents 0.24% of installed 

cost. Since conceptual engineering is necessary to assess potential unit modification options, 

EPA believes that these pre-award minor expenditures do not violate fiduciary obligations; 

rather, they provide valuable information for future planning for regulatory compliance, 

which appears to serve a sensible fiduciary purpose.

Inflationary Pressures

EPA’s modeling of the final Transport Rule projects significantly fewer units selecting 

pollution control retrofits as a cost-effective emission reduction strategy, as compared to 

EPA’s projections at proposal. Consequently, EPA does not anticipate cost escalation 

(inflationary pressures) from market suppliers. See Transport Rule preamble Table VII.C.2-

1: “Projected APC Retrofits for Transport Rule.”

Retrofit Emissions Control Costs

EPA recognizes that retrofit costs have aspects that are site-specific, depending in part on 

available space. EPA believes that the updated cost functions used to model projected 

retrofits for the final rule accurately represent recent industry cost outlays that themselves 

reflected site-specific cost drivers. For a discussion on retrofit cost modeling, please see 

“Documentation Supplement for EPA Base Case v.4.10_FTransport – Updates for Final 

Transport Rule”. 

Transport Rule – Harmful to Economy

EPA projects that the benefits to the public of the final Transport Rule far exceed the rule’s 

limited costs. Please see the final Transport Rule RIA for presentation of the rule’s projected 

costs, benefits, and economic impacts.

Switching from Lignite to Subbituminous

Commenters have questioned whether or not EPA’s modeling of available emission 

reductions has accurately captured the cost-effectiveness of increasing sub-bituminous 

consumption at units currently blending various shares of Texas lignite. While EPA believes 

that its main analyses of the Transport Rule accurately reflect the most cost-effective SO2

reductions available to Texas at the stringency level of a Group 2 state, in response to these 

 

39 “S&L to Develop Cost Estimates, Plans for FGD at Gerald Gentleman”; Utility E-Alert #1030, June 24, 2011; 

McIlvaine Company 
Page 16 of 19

concerns, EPA also conducted sensitivity analysis to address the cost-effectiveness of units 

continuing to blend lignite coal under the 2012 SO2 budget for Texas in the final rule. The 

purpose of this analysis is to determine if the Transport Rule’s SO2 assurance level for Texas is 

robust to varying levels of blending lignite and sub-bituminous coals at Texas facilities; in other 

words, the analysis investigates whether other cost-effective emission reductions exist in Texas 

aside from coal-switching to meet the state’s Transport Rule SO2 assurance level in 2012.

In this analysis, EPA constrained Texas units from increasing their blending of subbituminous coal beyond the level each unit reported to EIA for 2010. This is a conservative 

scenario for fuel blending, as EIA data shows that these units have significantly increased their 

level of sub-bituminous blending over several years leading to 2010 and thus already exhibit a 

multi-year trend of decreasing lignite consumption before the Transport Rule was promulgated. 

For the purposes of this sensitivity analysis, however, their sub-bituminous blending is prevented 

from growing beyond 2010 levels, notwithstanding the trend through 2010. Under these 

conditions, Texas is still projected to meet its 2012 SO2 assurance level using other cost-effective 

emission reduction strategies, including greater dispatch from lower-emitting generators, while 

still maintaining 2010 lignite blending levels. The sensitivity analysis reveals that Texas can still 

achieve its assurance level with other emission reductions available at the same marginal cost 

shared by all Group 2 states. That common marginal cost (the projected Group 2 SO2 allowance 

price in 2012) remains about $600 in both the main Transport Rule remedy analysis and this 

lignite-blending sensitivity analysis.40 Therefore, this analysis shows that the Texas SO2

assurance level is robust across a wide spectrum of lignite and sub-bituminous blending levels at 

Texas units.

Texas is still projected in this sensitivity scenario to emit less SO2 than its assurance level 

in both 2012 and 2014, even with its EGUs continuing to consume in the future the level of 

lignite reported to EIA in 2010. This sensitivity analysis therefore shows that Texas can sustain 

the operation of lignite mines and the provision of lignite coal to Texas EGUs while still costeffectively meeting the Transport Rule’s emission reduction requirements. Also, coal-switching 

is only one of many ways by which Texas can comply; EPA data show that 75% of Texas coal 

capacity will be scrubbed by 2012 and analysis shows that those units can increase their 

generation. Finally, natural gas-fired units benefiting from substantially expanding Texas natural 

gas supplies and low near-term prices can also increase their generation to help Texas costeffectively meet its 2012 SO2 budget. The following table presents the key parameters from this 

analysis supporting EPA’s conclusion that Texas can still cost-effectively comply with the 

Transport Rule even while maintaining the level of Texas lignite production and EGU blending 

reported in 2010 into the 2012 and 2014 compliance periods.

 

40 The projected allowance price is slightly higher than the $500 per ton cost threshold basis of the Group 

2 SO2 state budgets due to banking behavior under the trading programs.
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Key Findings from Texas Lignite Sensitivity

2012 2014

Remedy 

(revised)

Texas 

Lignite 

Sensitivity

Remedy 

(revised)

Texas 

Lignite 

Sensitivity

Group 2 Allowance 

Price $573 $581 $651 $659 

Texas SO2 Emissions* 244,000 280,000 266,000 281,000

Texas lignite production 

(million tons) 27.4 42.3 34.4 47.5

Change in Texas lignite 

production from 2010 

levels** -14.1 0.8 -7.1 6.0

*The 2012 and 2014 SO2 assurance level for Texas is 288,000 tons.

**EIA reported 2010 Texas lignite deliveries of 41.5 million tons.

Note: Remedy (revised) results are taken from the 

"TR_Remedy_Sensitivity_with_final_variability_limits" IPM run in the docket, 

whose results are also presented in Appendix F of the RIA. Texas Lignite 

Sensitivity results are taken from the 

"TR_Remedy_Sensitivity_Subbit_Restrictions" IPM run in the docket.

As these results show, even with Texas lignite blending at or above reported 2010 levels

in the 2012 and 2014 compliance periods, Texas SO2 emissions remain below the state’s 

assurance level and the Group 2 allowance price remains very stable, showing that Texas is still 

making cost-effective reductions to meet its Transport Rule obligations. The results in the table 

also demonstrate that Texas can achieve cost-effective compliance across a wide range of 

possible lignite production levels in the future, further demonstrating that the Transport Rule is 

not foreclosing the potential for Texas units to consume lignite coal. More details regarding this 

analysis can be found in the IPM model output files included in the docket for this rulemaking.

EPA believes this sensitivity analysis demonstrates the flexibility that is inherent in the 

Transport Rule programs as applied to Texas coal choice specifically and applied to all states 

covered by the Transport Rule more broadly. While EPA established emission reduction 

requirements for the states based on its modeling of the most cost-effective reductions available 

at cost thresholds used to define each state’s significant contribution and interference with 

maintenance, EPA chose to implement these emission reduction requirements as state emission 

budgets under which units can choose from a variety of emission reduction behaviors. This 

program design allows units to consider all relevant local economic factors when making 

dispatch, retrofit, and/or coal choice decisions factoring in the programs’ market-based cost of 

emitting SO2 and NOX.
Page 18 of 19

In addition, with the flexibility to submit a SIP to determine its preferred allowance 

allocation pattern beginning in 2013 under EPA’s expedited allowance allocation SIP process, 

Texas (as well as other states) has the freedom to augment preferred compliance activities as the 

state sees fit.

Plant Modifications - Switching from 100% Lignite to 100% Subbituminous 

A few commenters expressed concern about the technical feasibility of switching to 

100% subbituminous coal use in power plants that were originally designed for 100% lignite and 

are currently burning either 100% lignite or a blend of lignite and subbituminous. EPA carefully 

considered these comments and has confirmed its IPM modeling assumption that units designed 

for 100% lignite can readily switch to 100% subbituminous, or to a blend, by making relatively 

minor physical modifications that can be accomplished within the time frame available for 

compliance with the Transport Rule. 

A noteworthy example of a full switch from lignite to 100% subbituminous is the 480 

MW Gibbons Creek station of Texas Municipal Power Agency (TMPA): “In 1996, TMPA 

management switched exclusively to PRB [Powder River Basin] coal to improve the economics

of Gibbons Creek and to lower SO2 emissions. The switch required relatively minor changes to 

the physical plant and its control systems. Only one of the original eight mills was removed from 

service, although only five mills are needed for full load operation using PRB coal as fuel.”41

EPA understands that the primary reason that large pulverized coal boilers designed for a 

lower grade coal (lignite) can readily burn a higher grade coal (subbituminous) without major 

modifications is that in almost all respects such units are already “over designed” as regards the 

capabilities needed to successfully burn the higher grade coal. This fact is most apparent in 

comparing boiler furnace sizes: the plan area and height of a furnace designed for low-slagging 

lignite are at least as large as needed for subbituminous, and the dimensions of a high-slagging 

lignite furnace may be as much as 50% larger than needed for subbituminous.42 43 Similarly, the 

lower heating value of lower rank lignite requires that a lignite unit’s coal handling systems, 

pulverizers, boiler draft fans, air emission controls, and ash handling systems already have 

significantly greater capacity than needed for subbituminous. Lignite units that are currently

blending a significant share of subbituminous have likely already made the important but 

relatively minor improvements in coal handling and dust suppression systems needed to safely

accommodate the friability and dusting associated with subbituminous.44 45 Because of its low 

heating value, the rail transport cost for lignite is relatively high and lignite plants are therefore

typically located close to local lignite mines, so called “mine mouth” plants – often trucking or 

 

41 http://www.prbcoals.com/pdf/PRBCoalInformation/Power-Oct03-Smallmuni.pdf

42 Alstom Power, Inc, Clean Combustion Technologies, Fifth edition, 2009 

43 Babcock & Wilcox Company, Steam/its generation and use, Forty-first edition, 2005

44 http://www.powermag.com/coal/Luminants-Big-Brown-Plant-wins-for-continuous-improvement-and-safetyprograms_117.html

45 http://www.powermag.com/coal/Monticello-Steam-Electric-Station-Mount-Pleasant-Texas_464.html
Page 19 of 19

conveying coal to the plant. Switching from lignite to a subbituminous that comes from more 

distant sources may therefore entail some improvement to the rail spur and coal receiving system 

at some plants. These transport and coal handling requirements may already be in place at many 

lignite plants. Aside from these fundamental requirements, the more important modifications that 

may be required to facilitate a successful switch to subbituminous is the minor upgrading of 

current boiler cleaning systems46 to modern “water cannons”47 and “intelligent sootblowing”

48

systems to cope with various issues that might arise due to the slagging potential or higher “ash 

reflectivity” of subbituminous coal.

For all of the reasons discussed above, EPA believes that a switch from lignite to 100% 

subbituminous coal or to a blend with subbituminous is a technically feasible compliance option 

that can be accomplished at most lignite plants within the time frames available under the 

Transport Rule. Lignite units choosing to make a switch to higher grade subbituminous coal 

would be expected to experience reductions in total coal consumption and air pollutant 

emissions, an increase in boiler efficiency, and an increase in net electrical output.

 

46 http://www.cba-ssd.com/Applications/knowledgeBase/PRBcoal/FurnaceClean.htm

47 http://www.clydebergemann.com/content_manager/go/ID/28544/dbc/c40320c1b648988300168ec8918e855d

48 A. Manay, Clyde Bergemann, Inc, Study of the full implementation of the SmartCleanTM System at SRP Navajo 

Power Generation Unit 3, 2010 Coal Gen Conference, August 2010.