Page **1** of **19** 

## 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 t o Comments

U.S. Environmental Protection Agency Office of Air and Radiation Ju ly 2011Page **2** of **19**



### Contents Introduction ................................ ................................ ................................ ................................ . 3 Implementation I ssues ................................ ................................ ................................ ................ 4 Emission Control Capabilities ................................ ................................ ................................ .. 13 Implementation Costs ................................ ................................ ................................ ............... 14 Switching from Lignite to Subbituminous ................................ ................................ ................ 15Page **3** of **19**



### I **ntroduction** 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 recei ved 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, 201 0. An extensive general discussion of engineering feasibility is provided in preamble section VII.C.2, Compliance and Deploy ment of Pollution Control Technologies. Itaddresses man y 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 De adlines (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 I ssues  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.Page **4** of **19**



### 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. S ee 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 temporaril y until superseded b y EPA’s promulgation of the Transport Rule. While some utilities opted to temporaril y 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 so urces 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 owner s multiple options to attain compliance deadlines; namel y, unit owners may choose to maximize performance of existing pollution controls, shift power generation to cleaner units, expedite re trofit 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 certaint y which will allow utilities to improve planning efforts and, if necessary , amend long range strategic plans as they have successfull y done in response to past regulations. EPA is not responsible for aligning it s 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 accordingl y. Municipality Impacts and Challenges EPA anal yz ed and considered th e impacts of the Transport Rule on municipal EGUs. For a discussion on the rule's impact regarding mun icipalities, see RIA chapter 9. Complete Detailed Engineering Required for Initiating W ork 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 su bmission can occur. Detailed engineering is required for construction and installation activities.Page **5** of **19**

The Transport Rule generally sustains an already - present economic incentive for pollution control retrofit planning originall y imposed b y 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, shoul d have been completed and retained by many utilities . Some utilities may

have decided to temporarily postpone further deploy

ment 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 award s efficientl y and in a timely manner for desired retrofit s to make emission r eductions 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 so licit 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 fai ling 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 o f the Court’s ruling on CAIR, EPA believes any reasonable observer could have anticipate d as earl y 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 retr ofits, 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 pro grams. 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 economicall y 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 , thereb y supporting financing in pollution control retrofits. Furthermore, the financial industry views utilities with large cust omer 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 b y such large utilities. To reduce f inancing risk, utilities have the option to award
1 http://www.ovec.com/annrpt2009signed.pdf and http://www.ovec.com/Ne ws%20Release%20Clifty%20Creek%20Scrubbers%2012 - 15 - 10.pdfPage **6** of **19**

“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 retrofit s 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 compl yi ng with regulations. For instance, Indiana allows application for “Interim Approval” to commence construction , 2 Pennsylvania allows expedited review , 3 and Michigan, b y policy , attempts to complete permit to install (PTI) within 6 months 4 and usual ly take s less than 60 day s . 5 States implementing “lean” permitting principles 6 achieved significant reductions in permit processing times. Three of four states (M I, ID, IN ) ty pically process the permit in under 150 day s; the fourth state (IA) does it in 1 80 day s. Moreover, the agency plans to issue guidance for permitting authorities and thereb y 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 p re - 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 - c onstruction 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 ty pically averages 6 months and is obtained usually within one . 7 Furth ermore, 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 ev en 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.pdfPage **7** of **19**

consent decree to install such retrofits in the future (see preamble section VII.C.2 for more information) . Project Execution I

ssues N ecessitate L ong T

ime Periods Numerous comment er s claimed that actual project execution timeframes exceeded the time allotted by

the proposed rule . To illustrate the point, comment er s referenced specific retrofit project elements with asserted time requirements for their completion as part of the re trofitting process . EPA r ecognizes 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 SO 2 post - combustion projects relevant to this rulemaking are full y compatible with total labor hours required for completion. P roject 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 NO X SIP C all , and CAIR with the ability to perform accelerated project execution using a faster and more efficient Design - Build 8 process. T he power sector has recognized considerable efficiency gains through integrating standardized equipment designs, s ys tems approach, and modular construction techniques 9 as well as the formation of business alliances 10 to reduce frictional time lags . A typical control retrofit project consists of the following elements , several of which may occur simultaneousl y : 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 capita l commitment (detailed design, procurement, construction, commissioning / testing). Pre - award work elements are ty picall y executed sequentially since each preceding stage’s results inform the following stage; however, award work elements can be executed w ith “Lean Construction” techniques 11 to shorten time frames . Since a ty pical emission control device is a combination of smaller independent sub - sy stems, the design / build process with “lean construction” is highly suited for retrofits. For in stance, 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 ac tivities. 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 - CW LP - Dallman - 4 - Earns - POWERs Highest - 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 - Pow er - Stations - Retrofit - First - to - Meet North - Carolinas - Clean - Smokestacks - Act_63.htmlPage **8** of **19**

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 length y 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 adopt ion of proven faster execution methods evidenced by numerous units that have demonstrated FGD retrofit project completion in less than 30 months. Inparticular, commenters who cite examples of length y or delayed retrofit schedules from projects conducted during the highly uncertain period of the CAIR remand (when it was prudent to proceed cautiousl y) cannot reasonabl y expect such experiences to ap pl y 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 t imeframe 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 decision s ; examples of long completion timeframes offer more of a window into project management preferences rather than m inimum time requirements to complete the retrofit project expeditiously . The utility can encourage faster project completion by stipulat ing penalties during contract negotiation for failing to achieve commercially available dates. EPA believes completion of these retrofit projects is feasible b y 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 , sign ificant deploy ments were achieved in response to the NO X SI P Call which yielded notable efficiencies in retrofit deploy ments, 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 deploy ment schedule for the projected retrofit installations in the least - cost compliance pathway modeled for the final Transport Rule. (F or more discussion, see preamble section VII.C.2) . As described in that section, EPA anal yz ed 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 Desulfurizat ion 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/pu blic/ICAC_Carper_Response_110310.pdfPage **9** of **19**

T ransport 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 Compl iance The Jan 1, 2012 reductions projected b y IPM are based on: 1) operating existing installed controls; 2) completing installation of previously announced control retrofits coming online b y 2012; 3) Fuel switching / blending; and 4) installing combustion controls such as low NO X burners, overfire air or a combination thereof. EPA believes that these reduction strategies are feasible b y the start of the Transport Rule programs in 2012; for more discussion, see preamble section VII.C.2. Inadequate Labor Pool, Low Skill L evel &Insufficient Equipment Suppliers With current unemploy

ment rates 18 , sufficient quantities of engineers and skilled craft 19 exist for Transport Rule implementation. Li kewise, for the extreme case of local labor shortag es (which is not anticipated), this challenge can be overcome b y instituting a workforce development 20 action plan during project execution. This sector’s equipment suppliers and manufacturers are underutilized21 since 2010. Long Lead Times for Key Componen ts 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 r ecycle 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, b y Steve Katzberger, S ept 1, 2007 . 22 This comment selectivel y focuses on this table to claim that there is insufficient time available for equipment delivery

to comply

with the rule. However, earlier in th at article, a bar chart illustrates year - by - ye ar announced FGD start - ups from 2006 through 2015 for CAIR compliance. Clearl y, the long lead times tabulated for Dec 2006 reflect the more than 80 FGD s ys tems expected to be in - service for 2008 and 2009. EPA’s projections of least - cost compliance with the Transport Rule’s state b udgets 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 , th e projected FGD deplo ym ent 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 ref lects 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 - Im pact - of - Shortages - on - FGD - Prices_73.htmlPage **10** of **19**

equipment (Table 1, column Oct 2005). Furthermore, the longest lead time item (rubber lined recycle pumps) within Katzenberger’s article require d 112 weeks for delivery ; the final Tran sport 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 comment er does not cite any estimates of current lead times for equipment affecting retrofit deploy ment; rather , the commenter asserts future infeasibility

by relyingon outdated information which EPA believes does not accuratel y characterize the current state of the market or the opportunities for efficient and expeditious retrofit deploy ment discussed above and in section VII.C.2 of the final Transport Rule preamble . Multi
- unit Stations

– More T ime R equired EPA acknowledges that some of the plants that choose to retrofit with FGD control sy stems 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 l arger 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 outlay s. 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 Creek 24 and Kyger Creek 25 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 s ys tem 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 likel y to decrease subs tantially , 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.pdfPage **11** of **19**

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 o f 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 comm issioning or start - up time scheduling pose a material concern to Transport Rule compliance. ESP Upgrades Required for Fuel Switching Several comment er s indicated fuel switching may require electrostatic precipitator (ESP) upgrades. N ot all ESP ’s require i mprovements due to fuel switching / blending since: 1) an existing ESP may

have suf ficient design / operating margin s to accommodate increased particulate loading, and 2) the presence of a wet FGD augments PM control equipment by effectivel y removing parti culate 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 Po wer Plant refurbished an ESP within six months. 26 FRP pipe

– I

nsufficient S

pecialized Skilled Craft for Installation Commenters identified concerns about insufficient quantities of special skilled labor for installing and erecting fiberglass resin pipe ( F RP ) pipe. M ost FRP pipe manufacture r s offer installation training at the construction site or at the supplier’s premises , such as Ward Piping . 27 Fuel / Coal S

witching or Blending Issues Multiple comment er s 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 modificatio ns may be unnecessary . EPA carefull y considered the feasibility of coal switching when anal yz ing the availability of cost - effective reductions in each state in 2012 and 2014 . For more information , on fuel switching / blending, see preamble sect ion VII.C. 2.c. For IP M 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
- C

onstruction T

ime R equirements The compliance dead line 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.co m/wardabout.shtmlPage **12** of **19**

generated from Stuart and Killen stations scrubbers . 28 EPA notes, however, that retrofitting units do not necessaril y 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 perm itted 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 NO

X Burners
- Installation Time Requirements According to ICAC, low NO X burn er installation requires between 6 - 8 months . 30 With extensive low NO X 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 ty

pically be completed within 8 months . 31 Due to its simplicity and extensive installations, EPA considers this a mature technology which can be economically and reliabl y installed within the allotted timeframe for compliance. See preamble section VII.C.2. Stack / Chimney
- Construction Time R equirements EPA acknowledges that a wet FGD requires a “wet” stack which t ypically incorporates a fiberglass resin pipe ( FRP ) liner. The commenter’s claim that c himney engineering and construction requir e more than 30 months is inaccurate. Chimney size i s determined b y the scrubber’s location and discharge flow conditions , which the utility determines earl y on in the retrofit planning process and conceptual engineering design . C himney construction can utilize the “slip form” method to reduce erection tim e , with assembly t ypically requiring less than 60 day s. For instance, the Fayette power station stack #4 was poured within 39 day s 32 and Kiewit Power construction teams poured the Sandy Creek Energy

Station chimney (height: 360 feet) in less than 30 day s . 33 Dallman’s 440 ft unit #4 chimney required 28 day s for erection . 34 Thus, chimney engineering and construction are easily subsumed in the overall FGD deplo ym ent 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.c wlp.com/electric_division/generation/Dallman%204%20Power%20Plant%20of%20the%20Year.pdf 30 Institute of Clean Air Companies “T ypical Installation Timelines for NO X 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.c wlp.com/electric_division/generation/Dallman_4.htmPage **13** of **19**

CAIR Suffices... Transport Rule No t 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 NO X removal rates are consistent with commercially available equipment from multiple manufacture r s. In fact, current technology is capable of removing up to 90% of incoming NO X (subject a floor limit of 0.06 lbm NO X / MMBtu) on a continuous basis. The utility is responsible for ensuring that the s ys tem design accounts for all factors leading to degraded performance over the expected life of the SCR system. EPA does not see an y technical basis for claims that units originall y designed for partial year operation would experience NO X removal difficulties under all - ye ar operation . Properly operated and maintained SCR’s are capable of meeting their continuous design rating basis f

or NO X reduction (subject to floor limitations). SNCR Capability EPA examin ed 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 wa ll 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 assume d that SNCR operation occurred only during the ozone season. By comparing the heat input - weighted average NO X emission rate s between the ozone season and non - ozone season for calendar ye ars 2000 - 2010, the anal ys is 35 determined that overall SNCR removal efficiency averaged 35.6% ( within an observed range of 15 - 78%). Based on this analy sis, the EPA concludes that its SNCR removal efficiency assumptions represent real - world SNCR performance and are a ppropriate for Transport Rule promulgation.

35 SNCR Operating Units

– US EPA Data Analysis for Transport Rule RTC; see docketPage **14** of **19**

WFGD Capability Current original equipment manufacturers ( OEM ) commerciall y offer (and advertise) wet FGD technology that is capable of removing 98% of SO 2 . 36 For older w et FGD s, two options exist for enhancing perf

ormance: utilizing dibasic acid and / or upgrading internal comp onents. Other comment er s observed that EPA’s dry and w et FGD removal rate assumptions in the proposal’s power sector modeling reflected guaranteed performance levels (which depend upon particular fuel s and operating load s, among other factors) , while co ntinuous in - service removal rates are t ypicall y 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 an d w et 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

– E

xisting F uel Purchasing A greements Numerous comment er s argue d that the EPA failed to examine the financial implications for earl y termination of existing fuel contracts

– so called “breach ” of contract penalties - to achieve emission reductions through fuel switching. EPA does no t 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 yr s) . 38 Also, the electric power sec tor 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). Utilitie s therefore have a large degree of existing flexibility in year - to - ye ar 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 Rul e’s state emission budgets, which does not prescribe a specific degree of fuel switching at an y specific unit . Ina ddition, the Transport R ule’s program structure offers the flexibility to purchase allowance s 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 comment er s 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.htmlPage **15** of **19**

equipment; however, the expenditures for determining potential retrofit requirements (pre award 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 co st. 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 regul atory compliance, which appears to serve a sensible fiduciary purpose. Inflationary Pressures EPA’s modeling of the final Transport Rule projects significantl y 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 p reamble Table VII.C.2 - 1 : “Projected AP C Retrofits for Transport Rule.” Retro fit Emissions Control Costs EPA recognizes that retrofit costs have aspects that are site - specific , depend ing in part on available space . EPA believes that the update d cost functions used to model projected retrofits for the final rule accuratel y represent recent industry cost outlay s 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. 

### Sw **itching from Lignite to Subbituminous** C ommenters have questioned whether or not EPA’s modeling of available emission reductions has accuratel y captured the cost - effectiveness of increasing sub - bituminous consumption at units currently blending various s hares of Texas lignite. While EPA believes that its main analy ses of the Transport Rule accurately reflect the most cost - effective SO 2 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 CompanyPage **16** of **19**

concerns, EPA also conduc ted sensitivity analy sis to address the cost - effectiveness of units continuing to blend lignite coal under the 2012 SO 2 budget for Texas in the final rule. The purpose of this anal ys is is to determine if the Transport Rule’s SO 2 assurance level for Texas is robust to varying levels of blending lignite and sub - bituminous coals at Texas facilities; in other words, the anal ys is investigates whether other cost - effective emission reductions exist in Texas aside from coal - switching to meet the state’s Transport Rule SO 2 assurance level in 2012. In this analy sis, EPA constrained Texas units from increasing their blending of sub bituminous 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 purpo ses of this sensitivity anal ys is, 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 SO 2 assurance level using othe r cost - effective emission reduction strategies, including greater dispatch from lower - emitting generators, while still maintaining 2010 lignite blending levels. The sensitivity anal ys is reveals that Texas can still achieve its assurance level with other e mission reductions available at the same marginal cost shared b y all Group 2 states. That common marginal cost (the projected Group 2 SO 2 allowance price in 2012) remains about $600 in both the main Transport Rule remedy anal ys is and this lignite - blending sensitivity analy sis. 40 Therefore, this analy sis shows that the Texas SO 2 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 SO 2 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 analy sis therefore shows that Texas can sustain the operation of lignite mines and the p rovision of lignite coal to Texas EGUs while still cost effectivel y meeting the Transport Rule’s emission reduction requirements. Also, coal - switching is only one of man y ways by

which Texas can comply ; EPA data show that 75% of Texas coal capacity will b e scrubbed by

2012 and anal ys is shows that those units can increase their generation. Finally , natural gas - fired units benefiting from substantiall y expanding Texas natural gas supplies and low near - term prices can also increase their generation to help T exas cost effectivel y meet its 2012 SO 2 budget. The following table presents the key parameters from this anal ys is supporting EPA’s conclusion that Texas can still cost - effectively comply with the Transport Rule even while maintaining the level of Texas l ignite 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.Page **17** of **19** 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 SO 2 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 anal ys is can be found in the IPM model output files included in the docket for this rulemaking. EPA believes this sensitivity anal ys is demonstrates the flexibility that is inherent in the Transport Rule programs as applied to Texas coal choice specificall y and applied to all states covered b y the Transport Rule more broadl y. While EPA established emission reduction requirements for the states based on its modeling of the most cost - effective reducti ons 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 e mission 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 SO 2 and NO X .Page **18** of **19**

In addition, w ith 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 currentl y burning either 100% lignite or a blend of lignite and subbituminous. EPA carefull y considered these comments and has confirmed its IPM modeling assumption that unit s designed for 100% lignite can readily switch to 100% subbituminous, or to a blend, by making relativel y minor phy sical modifications that can be accomplished within the time frame available for compliance with the Transport Rule. A noteworth y 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 e xclusively to PRB [Powder River Basin] coal to improve the economics of Gibbons Creek and to l ower SO2 emissions. The switch required relatively minor changes to the phy sical plant and its control sy stems. Onl y one of the original eight mills was removed from service, although onl y five mills are needed for full load operation using PRB coal as fue l.” 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 successfull y 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 n eeded for subbituminous , and the dimensions of a high - slagging lign ite 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 s ys tems, pulverizers, boiler draft fans, air emission controls, and ash handling s ys tems already have significantl y greater capacity than needed for subbituminous. Li gnite units that are currently blending a significant share of subbituminous have likely already m a de the important but relativel y minor improvements in coal handling and dust suppression sy stems 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 ty picall y 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 Technolo gies, 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 - safety programs_117.html 45 http://www.powermag.com/ coal/Monticello - Steam - Electric - Station - Mount - Pleasant - Texas_464.htmlPage **19** of **19**

conveying coal to the p lant. S witch ing from lignite to a subbituminous that comes from more distant sourc es may

therefore entail some improvement to the rail spur and coal receiving s ys tem at s ome plants. T hese transport and coal handling requirements may already be in place at man y lignite plants. Aside from these fundamental requirements, the more important modification s that may be required to facilitate a successful switch to subbituminous is the minor upgrading of current boiler cleaning sy stems 46 to modern “water cannons” 47 and “intelligent sootblowing ” 48 sy stems 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 technicall y feasible compliance option that can be accomplished at most lignite plants within the time frames available under the Transport Rule. Li gnite 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, C lyde Bergemann, Inc, Study of the full implementation of the SmartCleanTM System at SRP Navajo Power Generation Unit 3 , 2010 Coal Gen Conference, August 2010.